Introduction

» 1520 hours — CPL overflight observes spill from pressure testing
sequence. Latitude 28° 56' 44.4", Longitude 89° 16' 47.9". Estimated
volume = 85 barrels.

> Surveillance flight sights oil on water at Latitude 28° 54.31'N and
Longitude 89° 14.66' W with an estimated volume of between 50 and
100 barrels.

October 5
> 1500 hours — Overflight locates slick at Latitude 28° 56.74! and
89° 16.8'. Slick described as being 0.75 miles by 200 yards.

Analysis of System Receipts and Deliveries and Leak Detection
At the time of the incident, Chevron considered the pressure safety low
(PSL) on the pipeline system as the primary method for detection of
pressure losses indicative of leaks in the pipeline system. The following is
excerpted from data provided by CPL in response to MMS questions
tegarding the incident. “As this offshore pipeline has MMS required PSL
shutdown equipment and meets [US]DOT 195.402 for operation with fail
safe equipment, CPL ‘lightly’ monitors this pipeline for abnormal conditions
including pipeline leaks. The controller displays, continuously, the SP 49
Onshore tank levels trend line for monitoring the operations of this system.
The pipeline graphic is pulled up intermittently to note LACT [lease
automatic custody transfer] status, specific tank level and pipeline pump
status, etc. By monitoring all of these, a controller when noting an abnormal

condition, makes the determination of a probable pipeline leak.”

During the early stages of the pipeline system startup following the
hurricane, tank level readings were being recorded at the CSC by SCADA.

15


Panel Investigation and Findings

Leak Detection Effectiveness Modeling - SP 49 Pipeline System

Tie-in Points of Platforms into SP 49 Pipeline System

SP45 MC 109 MC 20 SP 49
| Ss iN |
Q | tt |
| | It |
100 | | I 1 |
| | It |
-200 | | It |
| It |
g 300 | Ll |
& | IL 1]
= 400 | 1]
ram
8 | 1 |
= -500 | |
| I |
600 | |
|
-700 |
|
-800 |
0 2 4 6 8 10 12 14 #16 #18 20 22 24 26 28
Mile Post Number Along Pipeline Route
Platforms
SP45 MC109 MC20 = SP49
Current PSL Setting* (psig) 20 46 10 5
Scenario 1 - Rupture at Milepost 6.5 (SP 38)
Theoretical Operating Pressure® (psig) 8 150 51 71
Would PSL Shut in Pipeline? Yes No No No
Scenario 2 - Rupture at Milepost 23.1 (-780")
Theoretical Operating Pressure* (psig) 14 131 89 65
Would PSL Shut in Pipelines? Yes No No No
Scenario 3 - Rupture at Milepost 27.1 (MC 109)
Theoretical Operating Pressure* (psig) 5 102 77 35
Would PSL Shut in Pipeline? Yes No No No
Scenario 4 - Rupture at Milepost 27.9 (MC 20)
Theoretical Operating Pressure’ (psig) 0 90 70 23
Would PSL Shut in Pipeline? Yes No No No

36


Panel Investigation and Findings

SP 45 also pumps into the SP 49 pipeline system based on tank
management. During pumping operations, the pipeline pressure ranges from
approximately 0 to 200 psi, with the PSL set at 5 psi. The PSL has a 15-

second delay, to allow pump startup.

In both cases, sufficient back pressure remained at the departing platforms
to prevent the PSLs from sensing a leak. It is assumed that MC 109 did not
shut in on low pressure because of the leak location and system hydraulics.
Modeling of the system to support this conclusion is provided in the
following section. The SP 45 PSL did not shut-in the platform since
pressure did not drop below the 5 psi setting as a result of restrictions in the
pipeline. (Following the spill incident, OXY personnel are reported to have
found a partial paraffin plug that restricted flow through the pipeline.) The
restriction allowed the producer to pump into the pipeline at pressures
above the PSL setting in spite of a nearby catastrophic pipeline failure.
Simulations indicate that the PSL would have tripped on low pressure with a
pipeline rupture located in SP 38 had the inside diameter of the pipe not
been reduced by the buildup of paraffin.

Many pipeline oil spills are discovered through visual observation by
personnel stationed on platforms, planned flyovers during pipeline
inspections, or chance identification by personnel traveling through the area.
Efforts extended to identify oil spills and their origins assume that the oil
released from a subsea location will surface in the immediate vicinity of the

pipeline leak. This may not have been the case in the SP 38 spill.

Daylight overflights of the SP 49 pipeline system during the initial startup
phase did not identify the release of oil, suggesting that oil plumes may have

moved laterally subsea away from the leak location. Given the proximity of

32


The Department of the Interior Mission

As the Nation's principal conservation agency, the Department of the Interior has responsibility
for most of our nationally owned public lands and natural resources. This includes fostering
sound use of our land and water resources; protecting our fish, wildlife, and biological diversity;
preserving the environmental and cultural values of our national parks and historical places;

and providing for the enjoyment of life through outdoor recreation. The Department assesses
our energy and mineral resources and works to ensure that their development is in the best
interests of all our people by encouraging stewardship and citizen participation in their care.
The Department also has a major responsibility for American Indian reservation communities
and for people who live in island territories under U.S. administration.

The Minerals Management Service Mission

As a bureau of the Department of the Interior, the Minerals Management Service's (MMS)
primary responsibilities are to manage the mineral resources located on the Nation's Outer
Continental Shelf (OCS), collect revenue from the Federal OCS and onshore Federal and Indian
lands, and distribute those revenues.

Moreover, in working to meet its respon: ‘ies, the Offshore Minerals Management Program
administers the OCS competitive leasing program and oversees the safe and environmentally
sound exploration and production of our Nation's offshore natural gas, oil and other mineral
resources. The MMS Royalty Management Program meets its responsibilities by ensuring the
efficient, timely and accurate collection and disbursement of revenue from mineral leasing and
production due to Indian tribes and allottees, States and the U.S. Treasury.

The MMS strives to fulfill its responsibilities through the general guiding principles of: (1) being
responsive to the public's concerns and interests by maintaining a dialogue with all potentially
affected parties and (2) carrying out its programs with an emphasis on working to enhance the
quality of life for all Americans by lending MMS assistance and expertise to economic
development and environmental protection.


Recommendations

5. Chevon Pipe Line Company should establish leak detection
determination protocol on the SP 49 pipeline system using data collected
through the supervisory control and data acquisition system, reviewing
the data at such a frequency so as to identify promptly system
imbalances that would indicate a potential leak.

6. The MMS Gulf of Mexico Region should issue a safety alert to
operators throughout the GOMR area instructing them to adhere to
established post-hurricane pipeline operations startup procedures, and if

no procedures are in place, to develop and implement them.

41


Introduction

On September 29, at 1500 hours, the Chevron FTL, following discussions
with CSC, gave SP 45 permission to start up production operations and to
pump into the system. When all wells are on production, SP 45 has a
production rate of approximately 180 BOPD. Production is collected in a
200 barrel tank at the facility and then pumped into the SP 49 system when
the pump cycles on at approximately 75 percent of tank capacity. During
each pump—down phase, 100 barrels of oil are pumped into the system.

This sequence occurs approximately once every 12 hours.

On September 29, personnel on MC 20 began placing wells back on
production with produced oil being collected in a 120-barrel tank on the
platform. When the tank was near its capacity and was ready to be pumped
down, CPL staff were notified and permission was requested to pump
collected oil into the SP 49 system. CPL withheld permission for MC 20 to
pump, resulting in facility staff having to shut in all affected wells.

At 1630 hours, the Chevron Pipe Line FTL is reported to have grven MC
109 permission via telephone to resume production operations, with the
instructions that startup was to take place during daylight hours only, so that
overflights of the pipeline could be made to ensure prompt sighting of an oil
spill, should one occur. They were also instructed to look for released oil

around their platform.

When all wells are on production, MC 109 has a production rate of
approximately 10,300 BOPD. Full production, however, is not reached for
approximately three days. As a result, MC 109 never reached full
production during the post-hurricane startup sequence in which gas-lift wells
were being slowly placed on production. While it is reported that MC 109
came on production at approximately 1900 hours, charts indicate that the


As indicated in the table above, MC 109, MC 20 and SP 49”A” would be able to pump as
a single producer without shutting down on PSL commands at the current set points. This
is a result of the head loss in the system and the hydrostatic head of the —780 fsw at the
rupture location acting as back pressure on the system.

Effects of Changing PSL Settings to a Theoretical Value

The following table summarizes a theoretical PSL setting based upon the operating
pressures from Table 2.0 and if a single producer, pumping at current pumping rates,
would shutdown on a PSL command with a pipeline rupture at Milepost 23.1 (-780 fsw).

Producer Theoretical PSL setting Operating PSL
based on 15% below the Pressure protection
operating pressure of (psi)
Table 2.0.
(psi)

SP.45 Se 14 No
MC 109 147 131 Yes
MC 20 43 89 No
SP. 49 “A” 71 65 Yes

Table 2.21. Comparison of theoretical PSL setting vs. operating pressure for a single producer
with a pipeline rupture at Milepost 23.1 (-780 few).

** 5 psi is the lowest PSL setting allowed by the MMS.

Theoretically changing the PSL setting for each producer does not provide PSL protection
to the 10” pipeline system with only MC 20 pumping as a single producer. Also, SP 45
would not shutdown on PSL command until the pipeline reaches equilibrium.
Equilibrium will occur when seawater stops flowing into the pipeline and displaces the
oil into the tanks at SP 49 Onshore. At this point, the operating pressure at SP 45 would
be approximately —2 psi and would shutdown on PSL. With MC 109 and SP 49 “A”
pumping at the same time, the pressures would be about 177 psi and 110 psi respectively;
therefore, PSL protection would not shutdown MC 109 and SP 49 “A” in this scenario
until one producer completed a pumping cycle.

Effects of Installing a 60 psi Back Pressure Valve

The following table summarizes a theoretical PSL setting based upon the lowest
operating pressures from Table 2.01 and if a single producer, pumping at current pumping
rates, would shutdown on a PSL command with a pipeline rupture at Milepost 23.1 (-780
fsw).

Page 8


Attachment 5

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Attachment 8

CHEVRON 10" PIPELINE REPAIR -- SOUTH PASS 38 - OCTOBER 1998

OIL SEPARATING IN SOUTH END NORTH END (NO OIL)

BROKEN WELD (NORTH END) SEPARATED WELD (NORTH END)



K. Gaudet
1/14/99
Page 4

during fracture was primarily along the weld HAZs (except where the crack transitioned across the weld). The crack
was transgranular and little secondary cracking was observed.

Two secondary cracks, on the opposite side of the weld cap from the fracture surface were also observed. These
cracks were each approximately 3-4” in length, ran along the toe of the weld, and were oriented 180° from each
other (See Figs | & 2). In contrast to the failure, these cracks did not follow the HAZ’s but propagated into the base
metal. The crack faces were covered with corrosion products and one of the cracks had grown through-wall.

Pipe Chemistry and Mechanical Properties

Table 1
Pipe A Pipe B APISL
Grade B
Al <0.005 <0.005
Cc 0.26 0.26 0.27 max
Cr 0.02 0.02
Cu <0.005 <0.005
Mn 0.92 0.93 1.15 max
Mo <0.005 <0.005
Ni 0.01 0.01
P 0.010 0.010 0.030 max
Si <0.005 <0.005
s 0.014 0.015 | 0.030 max
Ti <0.005 <0.005
v <0.005 <0.005

Base metal samples from each side of the weld were analyzed for chemical composition with the results contained in
Table 1. Pipe chemistry was consistent with API 5L Grade B pipe.

Table 2
Specimen | Absorbed Energy | Lateral Expansion | % Shear
(ft-Ibs) (mils)

A 7 9 9
13 16 14
8 10 14

B 5 6 9

6.5 8 9

5 7 9

Base metal transverse impact testing was conducted at 32° F and the results are contained in Table 2. While the
impact values are low when compared against present standards, these values are not atypical for pipe manufactured
approximately 18 years ago.

C.N. Dykstal File: 04.15.05, 18.10, 70.33


Response Activities

Oil was first discovered on the water at approximately 1030 hours October 1, 1998. BP Exploration
immediately mobilized personnel and equipment to respond to the spill. The first response to the
spill location was dispersants. During the first two days they applied 3700 gallons of dispersant to
the slick. This dispersed approximately 1,138 bbls of oil.

Skimming operations on the initial release recovered approximately six barrels of oil. Skimming
recovered approximately 60 - 65 barrels of the second release. The difference between the two
amounts recovered is timing. For the first spill it took more than 20 hours to get a skimmer onsite.
The skimmers for the second release were pre-positioned near the location and started skimming in
just a few hours.

Mass Balance - After 5 days (barrels)

Oil Spilled Evaporated | Naturally Chemically | Recovered Remaining
Dispersed. Dispersed

3700 1221 185 1138 70 1086

7500 2475 375 1138 70 3442
The oil continued to degrade and has naturally dispersed into the water column.

Shoreline Impacts

Favorable weather and currents kept the initial oil spill offshore (See Attachment A) resulting in no
shoreline or wildlife impacts. The second release was driven N/NW towards the Mississippi River
Delta by strong southerly winds up to 20 - 25 knots. The leading edge of this slick was within state
waters at 1800 hours CDT on 10/4/98 and according to teams onsite, the first shoreline contact
occurred on the afternoon of October 5. Shoreline impact was minimal, however, with light sheens
extending several miles along the eastern gulf side of Southwest Pass, from the Burrwood Cut
southward to the rock jetties (see Attachment B). Small bands of a slightly heavier mousse were
observed just offshore at the convergence line of fresh and salt water. While estimates vary, USCG
onsite representative Chief Petty Officer Bill Hudgens estimated the oil washed ashore at less than

10 gallons.

Although shoreline impact was minimal, one State of Louisiana natural resource damage assessment
trustee suggested cleanup of the most heavily impacted sections of the beach. By the afternoon of
October 6, prior to actual deployment of cleanup equipment/crew, increasing seas dissipated the
minimal oil along the shoreline and made beach cleanup no longer necessary. Pass a Loutre State
Wildlife Management Area was not impacted by this spill.

Wildlife Impact:

Shoreline resources (marshes and tidal flats) and biological resources at risk (ish, shellfish, birds,
mammals, reptiles, habitats) were identified as part of the oil spill response effort. BP Exploration
and Chevron Pipeline contracted and staged wildlife response professionals from International Bird
Rescue and Rehab Center. Clean Gulf’s Wildlife Rehabilitation Trailer was pre-staged in the Venice


Introduction

at 0 psi throughout the test. Pressure readings recorded by SCADA at SP

49 were:
Time (hours) Pressure (psi Comment

1300 58
1400 73
1500 68
1530 165 Test started.
1600 165
1700 164
1730 164 Test completed.
1800 70
1900 79 Pressure stabilized at 72 psi.

On October 3, BP confirmed, through the use of a remotely operated
vehicle, that their pipeline (SN 9347), which was the suspected source of the
leak, showed no physical damage nor evidence of any leaking oil.

As the initial standup test on the SP 49 system was unsuccessful in
identifying the leak source, another more detailed pressure test procedure

was developed on October 3 with the assistance of MMS.

On October 4, the second standup test was conducted on the SP 49 pipeline
system. The pressure test medium was water, which was injected at SP 49.
Pressure readings at MC 109, SP 45, MC 20, and SP 49 Onshore once again
remained at 0 psi throughout the test. Pressure readings recorded by
SCADA at SP 49 were:

19


Panel Investigation and Findings

Actual current pressure setting of PSL at respective pipeline departing point.

Theoretical operating pressure with only one producer pumping at a time, with a rupture in the
pipeline at the noted location.

Comparison of theoretical operating pressure to current PSL setting and the determination if PSL
is set sufficiently to detect pipeline rupture and initiate shutdown of flow to pipeline.

As the preceding graph and scenarios show, hydrostatic pressure at the
modeled leak locations was found in many cases to emulate the back ,
pressure associated with a producer pumping into tankage at the SP 49
Onshore facility. This occurs as pressure losses associated with leaks are
offset by the pressure of seawater at the given depth of the leak location
below sea level. The operating pressure at the PSL sensing location at the
producing facility thus showed little if any change, giving no indication that
the pipeline integrity was no longer intact.

The report included a number of significant conclusions that bring into
question current policies affecting pipeline safety systems and the use of
PSLs as the primary leak detection methodology. Notably, CPL indicated
that, “The current PSL settings for each of the producers will not
automatically shut-in flow to the 10" SP 49 Pipeline System for a rupture at
all points in the system.” Further, modeling showed that reducing PSL
settings to 15 percent below the lowest operating pressure still would not
shut in flow from producers for a rupture at all points in the pipeline system.
The reduced setting, however, was found to shut in more producers than at

currently prescribed PSL settings in a number of scenarios.

Setting a nominal back pressure at SP 49 Onshore in conjunction with
reduced PSL settings proved to provide better pipeline protection than
currently approved PSL setting levels. Still, this improvement was only
marginally better and was highly dependent on the water depth at the leak

37


Producer | Theoretical PSL setting | Operating | PSL protection
based on 15% below Pressure
the operating pressure (psi)
of Table 2.01.
(psi)
SP 45 43 -8 Yes
MC 109 198 150 Yes
MC 20 94 51 Yes
SP 49 “A” 128 71 Yes

Table 2.12. Comparison of theoretical PSL settings with a 60 psi back pressure control valve
installed at SP 49 Onshore versus the operating pressure of a single producer with a rupture at
Milepost 6.5 (SP 38 area).

Theoretically, installing a 60 psi back pressure valve at SP 49 Onshore would provide
PSL protection to a single producer pumping into the 10” pipeline. However, if multiple
producers, such as MC 109 and SP 49”A”, are pumping simultaneously, they would not
shutdown on a PSL command until one producer completed the normal pumping cycle.

2.2 Pipeline Rupture at Greatest Depth of the 10” Pipeline

The greatest water depth the 10” SP 49 pipeline operates in is approximately 780 fsw and
occurs at Milepost 23.1. The hydrostatic pressure at this water depth is approximately
351 psi.

For this rupture location, SP 45 is located downstream of the leak site and MC 109, MC
20 and SP 49”A” is located upstream of the leak site.

Current PSL Settings
The following table summarizes the actual PSL setting for each producer, the theoretical

operating pressure with only one producer pumping at a time at current pumping rates and
whether the producer’s shutdown valve would close on a PSL command with a rupture in
the 10” pipeline at Milepost 23.1 (-780 fsw).

Producer Current PSL Operating PSL
setting Pressure (psi) protection
(psi)
SP 45 20 14 Yes
MC 109 46 131 No
MC 20 10 89 No
SP49A 5 65 No

Table 2.20. Comparison of current PSL setting vs. operating pressures for each producer with a
pipeline rupture at Milepost 23.1 (-780 fsw).

Page7


Abbreviations and Acronyms

BPD Barrels Per Day

BOPD Barrels of Oil Per Day

BP British Petroleum

CPDN Chevron Production

CPL Chevron Pipe Line Company

CRTC Chevron Research and Technology Center
CSc Customer Service Center (Chevron)
CSCC Customer Service Center Controller
CSR Customer Service Representative
CUSA Chevron, U.S.A.

FTL Field Team Leader

GOMR Gulf of Mexico Region

HAZ Heat Affected Zone

LACT Lease Automatic Custody Transfer
LCDR Lieutenant Commander

MAOP Maximum Allowable Operating Pressure
Mc Mississippi Canyon

MMS Minerals Management Service
MMSCFD Million Standard Cubic Feet per Day
MSO Marine Safety Office

NRC National Response Center

ocs Outer Continental Shelf

OXY OXY U.S.A., Inc.

PL OP Pipeline Operations Orders

PSI Pounds per Square Inch

PSL Pressure Safety Low

ROW Right-of-Way

SCADA Supervisory Control and Data Acquisition
SN Segment Number

SP South Pass

USCG U.S. Coast Guard

USDOT U.S. Department of Transportation
WD West Delta


Producer Current PSL Operating PSL
setting Pressure (psi) protection
(psi)
SP. 45 20 5 Yes
MC 109 46 102 No
MC 20 10 71 No
SP49A 5 35 No

Table 2.30. Comparison of current PSL setting vs. operating pressures for each producer with a
pipeline rupture at the MC 109 tie-in. (Milepost 27.1 and -640 fsw).

As indicated in the table above, MC 109, MC 20 and SP 49”A” would be able to pump as
a single producer without shutting down on PSL commands at the current set points. This
is a result of the head loss in the system and the hydrostatic head of the ~640 fsw at the

rupture location acting as back pressure on the system.

Effects of Changing PSL Settings to a Theoretical Value

The following table summarizes a theoretical PSL setting based upon the operating
pressures from Table 2.0 and if a single producer, pumping at current pumping rates,
would shutdown on a PSL command with a pipeline rupture at the MC 109 tie-in.
(Milepost 27.1 and -640 fsw).

Producer Theoretical PSL setting Operating PSL
based on 15% below the Pressure protection
operating pressure of (psi)
Table 2.0
(psi)

SP 45 5** 5 Yes
MC 109 147 102 Yes
MC 20 43 71 No
SP 49 “A” 771 35 Yes

Table 2.31. Comparison of theoretical PSL setting vs. operating pressure for a single producer
with a pipeline rupture at the MC 109 tie-in (Milepost 27.1 and -640 fsw).

** 5 psi is the lowest PSL setting allowed by the MMS.

Theoretically changing the PSL setting for each producer does not provide PSL protection
to the 10” pipeline system with only MC 20 pumping as a single producer. However, if
MC 109, MC 20 and SP 49 “A” are pumping at the same time, the pressures would be
about 102 psi, 84 psi and 37 psi respectively; therefore, PSL protection would shutdown
MC 109 and SP 49 “A” in this scenario and not MC 20.

Page 10


Producer | Theoretical PSL setting Operating PSL protection
based on 15% below Pressure
the lowest operating (psi)
pressure of Table 2.01.
(psi)
SP. 45 43 43 Yes
MC 109 198 131 Yes
MC 20 94 89 Yes
SP 49 “A” 128 65 Yes

Table 2.22. Comparison of theoretical PSL settings with a 60 psi back pressure control valve
installed at SP 49 Onshore versus the operating pressure of a single producer with a rupture at
Milepost 23.1 (-780 fsw).

Theoretically, installing a 60 psi back pressure valve at SP 49 Onshore would provide
PSL protection to a single producer operating on the upstream and downstream side of
the rupture. Also, if MC 109, MC 20 and SP 49”A” are pumping simultaneously on the
upstream side of the rupture, their pressures would be about 194 psi, 175 psi and 128 psi
respectively. MC 109 would shutdown on PSL, and the operating pressure at MC 20 and
SP 49”A” would decrease to 123 psi and 75 psi respectively. SP 49 ”A” would shutdown
on PSL then the operating pressure at MC 20 would decrease to 89 psi and shutdown on
PSL.

2.3 Pipeline Rupture at MC 109 Tie-In (Milepost 27.1)

At the MC 109 tie-in, the water depth is approximately 640 fsw. The hydrostatic pressure
at this water depth is approximately 288 psi.

For this rupture location, SP 45 is located downstream of the leak site and MC 109, MC
20 and SP 49”A” is located upstream of the leak site.

Current PSL setting

The following table summarizes the actual PSL setting for each producer, the theoretical
operating pressure with only one producer pumping at a time at current pumping rates and
whether the producer’s shutdown valve would close on a PSL command with a rupture in
the 10” pipeline at the MC 109 tie-in. (-640 fsw)

Page 9


Producer Current PSL Operating PSL
setting Pressure (psi) protection
(psi)
SP 45 20 0 Yes
MC 109 46 90 No
MC 20 10 70 No
SP49A 5 23 No

Table 2.40. Comparison of current PSL setting vs. operating pressures for each producer with a
pipeline rupture at the MC 20 tie-in. (Milepost 27.9 and -540 fsw).

As indicated in the table above, MC 109, MC 20 and SP 49”A” would be able to pump as
a single producer without shutting down on PSL commands at the current set points. This
is a result of the head loss in the system and the hydrostatic head of the —540 fsw at the

rupture location acting as back pressure on the system.

Effects of Changing PSL Settings to a Theoretical Value

The following table summarizes a theoretical PSL setting based upon the operating
pressures from Table 2.0 and if a single producer, pumping at current pumping rates,
would shutdown on a PSL command with a pipeline rupture at the MC 20 tie-in.
(Milepost 27.9 and -540 fsw).

Producer Theoretical PSL setting Operating PSL
based on 15% below the Pressure protection
operating pressure of (psi)
Table 2.0.
(psi)

SP 45 5¥* 0 Yes
MC 109 147 90 Yes
MC 20 43 70 No
SP 49 “A” 71 23 Yes

Table 2.41. Comparison of theoretical PSL setting vs. operating pressure for a single producer
with a pipeline rupture at the MC 20 tie-in (Milepost 27.9 and -540 fsw).

+** 5 psi is the lowest PSL setting allowed by the MMS.

Theoretically changing the PSL setting for each producer does not provide PSL protection
to the 10” pipeline system with only MC 20 pumping as a single producer.

Effects of Installing a 60 psi Back Pressure Valve

The following table summarizes a theoretical PSL setting based upon the lowest
operating pressures from Table 2.01 and if a single producer, pumping at current pumping
rates, would shutdown on a PSL command with a pipeline rupture at the MC 20 tie-in
(Milepost 27.9 and -540 fsw).

Page 12


Panel Investigation and Findings

SP 45 (OXY) “. . . does not have specific procedures for restarting a
platform after a hurricane although damage assessment is carried out first.”
Similar to BP, “OXY USA. Inc. requires approval from respective pipeline
prior to commencement of sales following hurricane evacuation.” SP 45
personnel did contact CPL to pump into the pipeline but indicated that “No
specific start-up instructions from Chevron Pipeline were noted after

hurricane evacuation.”

In conjunction with post-hurricane startup of the SP 49 pipeline, CPL stated
that they advised MC 109 to resume production at 1630 hours with the
condition that startup occur during daylight hours only to allow overflights.
MC 109 was also instructed to look around the platform for slicks. BP
indicates that CPL advised MC 109 to resume production at 1845 hours and
provided “. . . no restrictions on rates or daylight hours or any requirement
for stand-up tests or overflights . . .”. MC 109 reported that production
started at 1900 hours. A review of production charts for MC 109 shows

that pumping resumed at approximately 2200 hours.

A review of actions taken by the pipeline operating company showed that
CPL staff did not adhere to appropriate company “other than normal”
procedures regarding volume tracking.

Two additional problems contributed to the failure to identify the pipeline
leak promptly. First, recording of tank levels by CSC and the field
representative was inconsistent, with measurements being reported in feet
and inches versus feet and tenths of feet, e.g. tank level = 5 feet 6 inches
versus 5.5 feet. Second, the failure of CPL to have backup phone numbers
of producers prevented them from maintaining real-time communications

regarding actual production startup and pump rates.

30


Introduction

At the same time, the FTL had dispatched field personnel to the tank battery
to gauge the tank physically and to report the readings to the CSC
controller. Following are readings that show a comparison of the tank levels
tecorded by each method. Please note that the time intervals are not equal,

with lapses between noted readings ranging from several minutes to several

hours.
Tank Levels
Time SCADA Gauger
September 29 1800 71
1833 5.6
2100 4.6' 410%"
2140 4'10%" (OL)
2240 410 ¥%" (OL)
2340 4' 10 %" (OL)
2400 48 4°10 4"
September 30 0040 410%" (OL)
0140 4' 10%" (OL)
0240 4'10 %4" (OL)
0300 48 410%"
0340 4' 10%" (OL)
0440 4' 10%" (OL)
0500 4.9! 4'10 %" (OL)
1000 5.13'
1400 $.13'
1600 $.13'
2210 4'8 5" (OL)
2215 4.99' 4'8 3/4"

(OL) - Source of data is Operator Log.

All other data reported by CPL in incident report.
To assist in leak detection during start-up operations, CPL dispatched
helicopters to overfly the SP 49 pipeline system for prompt observation of
any sheens on the water. Details on flights and observations are noted in the

previous section on oil spill observation reports.

16


Introduction

pipe. The failure propagated circumferentially along the weld as this area
has a lower fracture toughness than the pipe. Neither of the primary
fractures began or ended at the weld buttons, which are oriented 180° from
each other. Inspections indicated that there was “no obvious initiation site

or evidence of a preexisting flaw . . .” in the pipe or weld.

Two additional secondary cracks were also found on the pipeline. The
cracks were approximately % inches in length and oriented 180° from each
other, possibly a result of “cyclic bending stress.” The cracks “did not
follow the HAZs but propagated into the base metal. The crack faces were
covered with corrosion products and one of the cracks had grown thru-

wall.” The cracks were determined to be “a result of corrosion-fatigue.”

22


Introduction

sequence noted above would yield a potential total volume spilled of 8,212

barrels.

The largest volume of oil that could have spilled during the incident takes
into account a review of historical production trends and the SP 49 pipeline
capacity. A review of MC 109 records indicates an average production rate
of 9,901 barrels per day; however, as noted earlier, full production levels are
not achieved for three days after full shutdown. Assuming that wells were
placed on production and the facility pumped at a rate of 333 barrels per
hour from 1900 hours on September 29 to 2015 hours on September 30, a
maximum of 8,400 barrels of oil could have been produced. With a daily
production rate of 180 barrels per day, SP 45 could have pumped 298
barrels of oil while on production from 1530 hours on September 29 to
0715 hours on October 1. The SP 49 pipeline system has a total static
capacity of 13,995 barrels. Considering that the pipeline depth ranges from
-110 feet at the leak location to a depth of -780 feet, a nominal amount of
oil would be expected to escape from the pipeline until the pressure
equalized at the leak point. It is assumed, however, that the pipeline was
covered with sufficient mud to prevent a significant release of oil through
line drainage. The largest volume of oil that could have spilled during this
incident, therefore, given the above assumptions and volumes, is 8,698

barrels.

Leak Source Identification

During the early afternoon of October 1, a standup test was conducted on
the SP 49 system to determine the exact location of the suspected pipeline
leak. Pressures at the platforms were monitored to ensure that check valves
were operating properly. Natural gas was the pressure test medium.
Pressure readings at MC 109, SP 45, MC 20, and SP 49 Onshore remained

18


Panel Investigation and Findings

Leak Detection Methodology
The primary leak detection system on this 156,288—foot long pipeline is that
provided by the use of PSLs on pipelines that depart oil production facilities
and connect via subsea tie-ins to the subject transportation pipeline system.
In addition, the SP 49 system is equipped with SCADA, which captures
pressure and flow rate data at both delivery and receiving points in the
system and is monitored in Houston. At the time of the pipeline spill, CSC
used SCADA data primarily for monthly line balancing and did not have
procedures established to continuously monitor SCADA data or trend
SCADA data to assist in the identification of shortages that might indicate a
pipeline leak.

Through the use of the PSLs, coupled with SCADA information, pipeline
leaks should be quickly identified and isolated. Identification of a potential
leak, however, is generally predicated on proper operation and settings of
the PSLs as well as adherence to established operating procedures that help
define what type of operational data need be collected to detect the presence
of a Jeak and at what intervals such data should be collected.

During normal operations, MC 109 pumps into the SP 49 pipeline as needed
for tank management. During pumping operations, the pipeline pressure
approaches 150 psi. The PSL to detect low pressure on the pipeline is
located on the transfer pump and is set at 46 psi, with a 45-second delay
after pump startup. This represents an approved departure from MMS
regulations. When the pumps are shut down, the pipeline pressure is 0 psi

or on a vacuum.

31


Introduction

September 29
» 1515 hours — No oil sighted during overflight by CPL.
» 1630 hours — No oil sighted during overflight by CPL.

September 30

> 0700 hours — Overflight of SP 49 system by CPL during system startup
did not reveal any oil on water.

> 1300 hours — Overflight of SP 49 system by CPDN during system
startup did not reveal any oil on water.

October 1

» 0645 hours — Overflight did not sight any oil slicks.

> 0900 hours ~ No oil sighted during overflight by CPL.

> 0930 hours — No oil sighted during overflight by CPL.

> 1030 hours — No oil sighted during overflight by CPL.

> 1030 hours ~ Oil slick sighted during helicopter flyover. Slick reported
to be located 12 miles west of MC 109.

» 1208 hours — NRC report to MSO Morgan City indicates location of
incident is WD Block 143 at 28° 39' 42" N, 89° 33'5" W. Slick
described as thick and dark brown, 200 feet wide and extending beyond
the horizon. Reported by Shell Offshore, Inc. Incident No. 457970.

» 1230 hours —- USCG reports to CPL of sighting of slick 27 miles by one
half mile located in WD Block 143.

» 1232 hours — NRC report to MSO New Orleans indicates location of
incident SP Block 87 at 28° 43' 12" N and 89° 25' 50" W with slick
described as silver/rainbow. Reported by Marathon Oil. Incident No.
457977.

» 1320 hours ~ No oil sighted during overflight by CPL.

» 1430 hours — No oil sighted during overflight by CPL.

13


Sheets

EXAMPLE OF HYDRAULIC CALCULATIONS.

[Coimpiete SP 49 Pipeline system — _ 7 SS
| : _Pxes_| a0a7a8t Pips) 343.5396] mT 7
i y PSL (psy 46) __|PSL (os) | z
P I a a3
TI 0.889937] _
= 550) . __|
\__ T 35
Sof A ce ee
09} :
7 a SS
ce
( 200] i nt 1
[- [Pips —. 157.3867 355-4198) psi) ~~ 564.7619) (ps) S837 :
7 . 1 r . i Z
7 T 7 T T H To 7 T
10" x.500" SP 45 Tie In to Onshore: "7 RGF S007 SP aS Tito 854" wall 10" x 894" point + 7 _
7 T I Hi H |
[777 fnew cies) ia densiy (oS) iia Gensiy, (EMIS ‘SA SST
{ seosity (cp) 33 hiscosty (cr :
uid veloty (USE) 73.s26089I urd velocty (Sec) —:
3.75] poet) :
7.00035} pipe roughness fj"
21720] ~Jovoe lengt ()
o]

keg |

inction factor

” nea loss (8)

head loss (ty)

[1O" x 854" Deepestto MC 1
T

[10° x84" MC 2071 to SPA5A
7 ;

| [Rai sensi emtegy
lwscosity (eo) [viscosity (op)
ud velocity (Weed)
Pipe id tr) :
pipe roughness (ft) _
pipe length (f)
Leaf) =
friction factor ‘DO2eTz2, rction factor 0.033659)
7 a fad Toss (RY 214 6787 [head loss (ft) 11622768 head loss (ft) 2850282!
¢ a + z =
7 - 1 | Tt —— t
i : 7 ‘ — —
2.337" SP 45 T1t0 SPAS ° [er x 406" ME 109 Tito MC 109 “|x 432 MC 20 to MC 20
~ |ncietonsty Tem) TSE BamT| | [Roig Sensty oma)” Ee a DES AO
[uscosity (cp) a 5| lviscosity co) j 15 liscosity (ep) i a”
uid velocity (ft/sec) 1.367608] uid velocity (ft/sec) 2.5768 fuid velocity (twsec)
pins ia tiny Fi 7 ATE) ~ [Pipe a (in, i
pipe roughness (Ap 2 70.0008] pipe roughness (A) ___|
pipe length (ft) i. 36360] pipe length ()_—
ff u I (Offbeat
faction factor O,0aaTas Coss ction factor 710428081 >
ead loss (A) iai2t Tae 776 head lass (fh) 148.6415"

Page 1


Effects of Installing a 60 psi Back Pressure Valve

The following table summarizes a theoretical PSL setting based upon the lowest
operating pressures from Table 2.01 and if a single producer, pumping at current pumping
rates, would shutdown on a PSL command with a pipeline rupture at the MC 109 tie-in
(Milepost 27.1 and-640 fsw).

Producer | Theoretical PSL setting Operating PSL protection
based on 15% below Pressure
the lowest operating (psi)
pressure of Table 2.01.
(psi)
SP 45 43 32 Yes
MC 109 198 102 Yes
MC 20 93 77 Yes
SP.49 “A” 127 35 Yes

Table 2.32. Comparison of theoretical PSL settings with a 60 psi back pressure control valve
installed at SP 49 Onshore versus the operating pressure of a single producer with a rupture at MC
109 tie-in (Milepost 27.1 and -640 fsw).

Theoretically, installing a 60 psi back pressure valve at SP 49 Onshore would provide
PSL protection to a single producer operating on the upstream and downstream side of
the rupture. Also, if MC 109, MC 20 and SP 49”A” are pumping simultaneously on the
upstream side of the rupture their pressures would be about 102 psi, 84 psi and 37 psi
respectively. Therefore, all three producers would shutdown on PSL.

2.4 Pipeline Rupture at MC 20 Tie-In (Milepost 27.9)

At the MC 20 tie-in, the water depth is approximately 540 fsw. The hydrostatic pressure
at this water depth is approximately 243 psi.

For this rupture location, SP 45 and MC 109 is located downstream of the leak site and
MC 20 and SP 49”A” is located upstream of the leak site.

Current PSL setting

The following table summarizes the actual PSL setting for each producer, the theoretical
operating pressure with only one producer pumping at a time at current pumping rates and
whether the producer’s shutdown valve would close on a PSL command with a rupture in
the 10” pipeline at the MC 20 tie-in. (-540 fsw)

Page 11


K. Gaudet
1/14/99
Page 2

South Pass 49 Pipeline
Pipe A

0

oatwewsuron  [{{({II])

Figure 1 Schematic of pipe “A” side of fracture surface indicating location of fracture, secondary cracks,
and metallographic samples.

C.N. Dykstal File: 04.15.05, 18.10, 70.33


Introduction

Background

The South Pass (SP) 49 pipeline system, which originates in SP Block 49 and
connects to the SP 49 Onshore facility, is partially located off the Louisiana
coast and is part of the West Bay Pipeline System (see Attachment 2). The
SP 49 system is operated by CPL but is jointly owned by Mobil Eugene
Island Pipeline Company, Pogo Offshore Pipeline Company, Unocal Pipeline
Company, BP Offshore Pipelines, Inc., Conoco, and CPL.

The pipeline system consists of a 10-inch right-of-way (ROW G07561)
pipeline (SN 5625), 156,288 feet in length, of which 125,279 feet are in OCS
waters. The system has an operating capacity of 59,000 barrels per day
(BPD) and a static capacity of approximately 13,995 barrels. Recent
throughput was 17,250 BPD. The pipeline, constructed in 1980, has a
maximum allowable operating pressure (MAOP) of 1,440 pounds per square
inch (psi) and normal operating pressures that vary from 0 psi to 360 psi
along the length of the pipeline. Water depths along the pipeline’s route,
which crosses through SP Blocks 49, 50, 52, 53, 46, 45, 37, 38, 27, 26, and
25, and Mississippi Canyon (MC) Blocks 151, 150, 149, range from sea level
to approximately 780 feet deep.

Four primary oil production platforms are connected to the pipeline,
including SP 45 A, operated by OXY; MC 109 A, operated by BP;

MC 20 A, operated by Taylor Energy Company; and SP 49 A, operated by
Chevron, U.S.A. (CUSA) (see Attachment 3). Two additional platforms, SP
49 B and SP 49 C, produce to SP 49 A, where production is metered. Asa
result, only SP 49 A will be addressed. For the remainder of the report
platforms will be identified by their location only, e.g. CUSA’s SP 49 A will
be referred to as SP 49.


Panel Investigation and Findings

after the pipeline failure. Another assumption critical to the approximation is
that the pipeline was parted at the time SP 45 resumed production on
September 29.

The total volume that is expected to have spilled during the subject pipeline

leak is 8,212 barrels. The volume is based upon the following assumptions:

Volume Description Volume (bbls)
a. Volume pumped after startup 8,066
b. Volume to fill ines for pressure test 122
c. Volume lost during pressure tests 85
d. Volume recovered to tank (61)
TOTAL 8,212

Startup Procedures and Chronology
The CPL does have operating procedures that dictate actions to be taken
following an “other than normal circumstance,” as in the case of Hurricane
Georges. The CPL procedures excerpted from the Chevron Pipe Line
Company — Gulf Coast Region — West Bay Pipeline System Manual,
presented below, deal with planned startup procedures that must be
followed for system startup following normal or other than normal
circumstances:
a) “Start-up of the system or a segment of the system will be coordinated
by CSCC [customer service center controller], CSR [customer service
tTepresentative], and the FTL.
b) “After system integrity has been verified and a segment of the system is
teady for start-up, the Venice FTL will coordinate system start-up with the
various field producers. Coordination includes verifying that Empire/Ostrica

28


RESULTS

1.0 Static Conditions (no flow conditions)

The following table summarizes the elevation of the tanks’ liquid level at SP 49 Onshore,
the producers’ SDV elevations (all referenced to sea level) and the corresponding
calculated static pressures based on the respective crude oil gravities.

Location Elevation referenced Static Pressure
to sea level (psi)
(feet)
SP 49 Onshore +10 0
Tank Liquid Level
SP. 45 +60 -17
MC 109 +65 -23
MC 20 +60 -18
SP 49 “A” +75 -17

Table 1.0. Elevations of SP 49 Onshore tanks’ liquid level, producers’ SDV elevations and
corresponding static pressure.

The elevations of the producers’ SDV’s and associated pressure pilots are much higher
than the elevations of the tanks’ liquid level at the SP 49 Onshore Facility. This results in
vacuum pressures at the producers’ platform when the pipeline is at static conditions.

The following table summarizes the elevation of the producers’ SDV elevations and the
corresponding calculated static pressures based on the respective crude oil gravities with
a 60 psi back pressure valve installed at SP 49 Onshore

Location Elevation referenced Static Pressure
to sea level (psi)
(feet)
SP.45 +60 29
MC 109 +65 26
MC 20 +60 30
SP 49 “A” +75 30

Table 1.01. Elevations of SP 49 Onshore tanks’ liquid level, producers’ SDV elevations and
corresponding static pressure with a 60 psi back pressure valve installed at the SP 49 Onshore
Facility.

Page 3


2.1 Pipeline Rupture at Milepost 6.5 (SP 38 Incident point):

At Milepost 6.5, the water depth is approximately 100 fsw. The hydrostatic pressure at
this water depth is approximately 45 psi.

Current PSL Settings:
The following table summarizes the actual PSL setting for each producer, the theoretical

operating pressure with only one producer pumping at a time at current pumping rates and
whether the producer’s shutdown valve would close on a PSL command with a rupture in
the 10” pipeline at Milepost 6.5 (SP 38 area).

Producer Current PSL Operating PSL
setting Pressure (psi) protection
(psi)
SP.45 20 -8 Yes*
MC 109 46 150 No
MC 20 10 51 No
SP49 A 5 71 No

Table 2.10. Comparison of current PSL setting vs. operating pressures for each producer with a
pipeline rupture at Milepost 6.5 (SP 38 area).

As indicated in the table above, MC 109, MC 20 and SP 49”A” would be able to pump as
a single producer without shutting down on PSL commands at the current set points. This
is a result of the head loss in the system and the hydrostatic head of the —100 fsw at the
rupture location acting as back pressure on the system. The back pressure nearly
emulates a producer pumping into tankage at the SP 49 Onshore Facility. With all four
producers pumping into the pipeline at current pumping rates, the pressure at SP 45
would be about 54 psi, assuming a fully open 4” schedule 80 pipeline. SP 45 would not
shutdown on a PSL command in this scenario.

* Explanation of SP 45:

Theoretical calculations for a fully open 4” schedule 80 pipeline indicate SP 45 should have
shutdown on PSL; however, SP 45 was able to flow into the pipeline as a single producer. After
the repairs to the 10” pipeline, the 4” SP 45 pipeline would shutdown on high pressure. An
investigation by the producer indicated a paraffin plug in the 4” pipeline that prohibited flow. The
paraffin build up on the walls of the 4” pipeline increased the back pressure at SP 45 allowing
them to pump at pressures above the PSL setting during the SP 38 incident.

Effects of Changing PSL Settings to a Theoretical Value

The following table summarizes a theoretical PSL setting based upon the operating
pressures from Table 2.0 and if a single producer, pumping at current pumping rates
would shutdown on a PSL command with a pipeline rupture at Milepost 6.5 (SP 38 area).

Page 5


The theoretical PSL setting is a calculated value that was obtained from the operating
pressures of the producers in Table 2.0. This was calculated for each producer as shown
in the following example.

Example 1: Theoretical PSL setting for MC 109.

MC 109 Operating Pressure from Table 2.0: 173 psi

Subtract 15% (operating range) - 26 psi

Theoretical PSL set point: 147 psi
Producer Theoretical PSL setting Operating PSL

based on 15% below the Pressure protection
operating pressure of (psi)
Table 2.0.
(psi)

SP. 45 3** -8 Yes
MC 109 147 150 No
MC 20 43 51 No
SP. 49 “A” TI 71 Yes

Table 2.11. Comparison of theoretical PSL setting vs. operating pressure for a single producer
with a pipeline rupture at Milepost 6.5 (SP 38 area).
** 5 psi is the lowest PSL setting allowed by the MMS.

Theoretically changing the PSL setting for each producer does not provide PSL protection
to the 10” pipeline system with only MC 109 or MC 20 pumping as a single producer.
With MC 109 and SP 49 pumping at the same time, the pressure at SP 49 “A” would be
about 263 psi; therefore, PSL protection would not shutdown SP 49 “A” in this scenario.
Also, with all four producers pumping at the same time the pressure at SP 45 would be
approximately 54 psi; therefore, PSL protection would not shutdown SP 45.

Effects of Installing a 60 psi Back Pressure Valve

The following table summarizes a theoretical PSL setting based upon the operating
pressures from Table 2.01 and if a single producer, pumping at current pumping rates
would shutdown on a PSL command with a pipeline rupture at Milepost 6.5 (SP 38 area).

Page 6


Panel Investigation and Findings

Following are the overage/shortage figures for the SP 49 system for 1998:

SOUTH PAss 49 SYSTEM RECEIPTS FOR 1998

Month Receipts Over/Short % Over/Short
(barrels) (barrels)

January 449,640 (67) -0.01
February 413,517 (100) - 0.02
March 470,790 (683) -0.15
April 465,389 (577) - 0.12
May 549,819 (663) -0.12
June 541,045 411 0.08
July 497,556 (5,683) -1.10
August 455,402 6,742 1.50
September 398,104 (9,677) - 2.40
October 160,572 1,135 0.71
November 477,259 (1,228) - 0.26
December $27,524 (725) -0.14
Year-to-Date 5,406,617 (11,115) -0.21

It should be noted that prior to the pipeline leak, CSC performed line
balances on a monthly basis.

Factors Affecting the Surface Appearance and Observation of Oil
Estimates of the spill volume, based on aerial surveillance during the early
phases of spill response, indicated a total volume of 3,700 barrels of oil. This
is contrasted with the initial estimated volume of approximately 7,500 barrels
of oil that was recorded pumped into the SP 49 system and presumed spilled
into the Gulf of Mexico beginning on September 29. The variance in spill

25


The following table summarizes the theoretical operating pressure if a single producer
were pumping ratably into the onshore storage tanks and a 60 psi back pressure valve was
installed at the SP 49 Onshore Facility.

Producer Lowest Theoretical
Operating Pressure
(psi)
SP.45 42
MC 109 233
MC 20 53
SP 49 “A” 67

Table 3.01. Theoretical operating pressure for a single producer pumping ratably into
tankage with a 60 psi back pressure valve installed at SP 49 Onshore.

3.1 Pipeline Rupture at Milepost 6.5 (SP 38 Incident point):

At Milepost 6.5, the water depth is approximately 100 fsw. The hydrostatic pressure at
this water depth is approximately 45 psi.

Effects of Ratable Pumping
The following table summarizes a theoretical PSL setting based upon the operating

pressures from Table 3.0 and if a single producer, pumping ratably, would shutdown on a
PSL command with a pipeline rupture at Milepost 6.5 (SP 38 area).

Producer Theoretical PSL setting Operating PSL
based on 15% below the Pressure protection
operating pressure of (psi)
Table 3.0.
(psi)

SP 45 S¥ee -15 Yes
MC 109 147 150 No
MC 20 See 5 Yes
SP 49 “A” 6 5 Yes

Table 3.10. Comparison of theoretical PSL setting vs. operating pressure for a single producer
pumping ratably with a pipeline rupture at Milepost 6.5 (SP 38 area).
*** 5 psi is the lowest PSL setting allowed by the MMS.

Theoretically, with a ratable system, MC 109 pumping as a single producer would not
shutdown on a PSL command with a rupture at Milepost 6.5. Also, if all four producers
are pumping simultaneously, none of the producers would shutdown on PSL. In this
scenario, with MC 109 not shutting down on PSL, allows MC 20 and SP 49 “A” to pump
without shutting down.

Effects of Ratable Pumping and Installing a 60 psi Back Pressure Valve

Page 16


Investigation and Report

Procedures

Name Agency/Department

Buddy Sheets U.S. Department of Transportation (USDOT),
Office of Pipeline Safety

LCDR George Butler U.S. Coast Guard (USCG), Marine Safety Office,
Morgan City

On November 17, 1998, investigation panel members, including David M.
Moore, Frank Torres, Mike Joseph, and Buddy Sheets, attended a meeting
conducted at Chevron Pipe Line Company’s (CPLs) office located at 935
Gravier Street, New Orleans, Louisiana. The purpose of the meeting was to
obtain data collected by CPL staff resulting from their internal investigation
of the pipeline spill incident as well as to begin preliminary inquiry into

events surrounding the spill.

The meeting consisted of presentations by CPL personnel on the sequence
of events, repair procedures, and recommended action items, and was
followed by an open discussion period. A copy of the CPL report “South
Pass 49 Pipeline Root Cause Analysis and Pipeline Repair Presentation —
11/17/98," was obtained for panel review and was made part of MMS
investigative files. A copy of the report was subsequently forwarded to the

USCG panel representative who was unable to attend the presentation.

On January 14, 1999, the investigation panel chairman forwarded a list of
questions to CPL. The questions were developed based upon input from all
panel members seeking additional data or clarification of information
presented in CPL’s internal report. Questions focused mainly on data
required for accounting of oil presumed lost as a result of the spill, internal

company communications, and standard versus upset operating practices.


Investigation and Report

Authority

On or about September 29, 1998, an oil spill occurred in the Gulf of Mexico
in South Pass (SP) Block 38 as a result of a pipeline rupture. The spill
volume, in conjunction with activities surrounding source identification,
resulted in a decision by the Minerals Management Service (MMS) to
conduct an investigation of the incident. The investigative process is
designed to be a fact-finding proceeding with no civil or criminal issues and
no adverse parties and with the ultimate purpose being to prepare a public
report. The report is a compilation of relevant facts surrounding the spill

and includes findings, conclusions, and recommendations.

The following MMS personnel were designated as members of a spill
investigation panel by the Regional Director of the MMS Gulf of Mexico

Region (GOMR):

Name Department/Section

David M. Moore Field Operations, Pipeline Section

Frank Torres Field Operations, Pipeline Section

Mike Joseph Production and Development, Surface Commingling

and Production Measurement Section
The panel members were named by memorandum dated October 20, 1998
(see Attachment 1), pursuant to Section 208 (subsections 22 d, e, and f) of
the Outer Continental Shelf (OCS) Lands Act, as amended (1978), and the
Department of the Interior Regulations 30 CFR Part 250. David M. Moore

was designated as panel chairman.

Staff from other agencies that have direct authority over right-of-way
(ROW) pipelines in State offshore waters or offshore spill response were

also solicited by MMS to assist in the investigation, and included:


Introduction

1522 hours — NRC report to MSO New Orleans indicates location of
incident MC Block 109 at 28° 5'0" N, 90° 0' 0" W with volume shown
as 7,500 barrels of crude oil. Reported by BP. Incident No. 458019.
1530 hours — No oil sighted during overflight by CPL.

1600 hours — Spill reported to be 30 miles southwest of mouth of
Mississippi River delta. Spill size 27 miles by 7 miles. Estimated
volume is 3,700 barrels.

1645 hours — No oil sighted during overflight by CPL.

USCG overflight observed dark brown slick with light sheen 15 nautical
miles by 1 nautical mile running NE to SW. Position 28° 50.6' North
and 89° 12.8' West to 28° 51.7' North and 89° 19.7' West.

October 2

»

»

1100 hours — No oil sighted during overflight by CPL.
1229 hours — USCG locates sheen approximately 5 x 5 miles in position
28° 54.8' North and 89° 16.3' West. Described as light rainbow with

areas of heavier rainbow.

October 3

»

>

1245 hours — No oil sighted during overflight by CPL.
1715 hours — No oil sighted during overflight by CPL.

October 4

»

>

»

0700 hours — No oil sighted during overflight by CPL.
0900 hours — No oil sighted during overflight by CPL.
1145 hours — Aerial surveillance finds no oil on water.
1245 hours — No oil sighted during overflight by CPL.

1315 hours — Aerial surveillance finds no oil on water.

14


Investigation and Report

faxed to personnel at BP Exploration, Inc. (BP), OXY USA, Inc. (OXY),
and CPL. By March 29, all affected parties had responded to the questions
posed by the investigation panel. The panel chairman also conducted a
telephone interview with an employee of Taylor Energy Company on

March 8.

Preparation of the draft report was completed and it was forwarded to panel
members on April 13, 1999. Following inclusion of revisions by members
and completion of the MMS publication approval processes, the final report
was published for public review in July 1999.


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Producer Theoretical PSL setting Operating PSL
based on 15% below the Pressure protection
operating pressure of (psi)
Table 3.0.
(psi)

SP. 45 See 8 No
MC 109 147 131 Yes
MC 20 5¥e* 39 No
SP 49 “A” 6 40 No

Table 3.20. Comparison of theoretical PSL setting vs. operating pressure for a single with a
pipeline rupture at Milepost 23.1 (-780 fsw).
*+* 5 psi is the lowest PSL setting allowed by the MMS

Theoretically, with a ratable system, SP 45, MC 20 and SP 49”A”, pumping as a single
producer, would not shutdown on a PSL command with a rupture at Milepost 23.1. Also,
SP 45 would not shutdown on PSL command until the pipeline reaches equilibrium.
When equilibrium is achieved the operating pressure at SP 45 would be approximately -8
psi and would shutdown on PSL.

Effects of Ratable Pumping and Installing a 60 psi Back Pressure Valve

The following table summarizes a theoretical PSL setting based upon the lowest
operating pressures from Table 3.01 and if a single producer, pumping ratably, would
shutdown on a PSL command with a pipeline rupture at Milepost 23.1 (-780 fsw).

Producer | Theoretical PSL setting Operating PSL protection
based on 15% below Pressure
the lowest operating (psi)
pressure of Table 3.01.
(psi)
SP. 45 36 40 No
MC 109 198 131 Yes
MC 20 45 39 Yes
SP 49 “A” S7 40 Yes

Table 3.21. Comparison of theoretical PSL settings with a 60 psi back pressure control valve

installed at SP 49 Onshore versus the operating pressure of a single producer pumping ratably with
a rupture at Milepost 23.1 (-780 fw).

Theoretically, a ratable system and installing a 60 psi back pressure valve at SP 49
Onshore would not provide PSL protection to SP 45 operating on the downstream side of
the rupture. However, if MC 109, MC 20 and SP 49”A” are pumping simultaneously on
the upstream side of the rupture, their pressures would be about 154 psi, 84 psi and 78 psi
respectively. MC 109 would shutdown on PSL, and the operating pressure at MC 20 and
SP 49”” would decrease to 48 psi and 42 psi respectively. SP 49 ”A” would shutdown

on PSL then the operating pressure at MC 20 would decrease to 39 psi and shutdown on
PSL.

Page 18


Theoretically changing the PSL setting for each producer does not provide PSL protection
to the 10” pipeline system with MC 20 and SP 49 “A” pumping as a single producer.

Effects of Ratable Pumping and Installing a 60 psi Back Pressure Valve

The following table summarizes a theoretical PSL setting based upon the lowest
operating pressures from Table 3.01 and if a single producer, pumping ratably, would
shutdown on a PSL command with a pipeline rupture at the MC 20 tie-in (Milepost 27.9
and -540 fsw).

Producer | Theoretical PSL setting Operating PSL protection
based on 15% below Pressure
the Jowest operating (psi)
pressure of Table 3.01.
(psi)
SP 45 36 21 Yes
MC 109 198 93 Yes
MC 20 45 22 Yes
SP.49 “A” 57 16 Yes

Table 3.41. Comparison of theoretical PSL settings with a 60 psi back pressure control valve
installed at SP 49 Onshore versus the operating pressure of a single producer pumping ratably with
arupture at the MC 20 tie-in (Milepost 27.9 and -540 fsw).

Theoretically, installing a 60 psi back pressure valve at SP 49 Onshore would provide
PSL protection to all producers pumping as single units on both the upstream and
downstream side of the rupture. Also, if SP 45 and MC 109 were pumping
simultaneously on the downstream side of the rupture, their pressures would be about 25
psi and 93 psi respectively. Both producers would shut down on a PSL command. If MC
20 and SP 49 ”A” were pumping simultaneously on the upstream side of the rupture,
there pressures would be approximately 22 psi and 16 psi respectively; therefore both
producers would shutdown on a PSL command.

3.5 Conclusions for Section 3

¢ Ifthe system was ratable and the PSL settings for each of the producer were set to
15% below the lowest operating pressure as calculated by individual pumping rates,
the PSL’s do not automatically shut-in flow on the 10” SP 49 Pipeline System for a
pipeline rupture at Milepost 6.5, Milepost 23.1, Milepost 27.1 and Milepost 27.9.

« Ifa 60 psi back pressure valve was installed on a ratable system at the South Pass 49
Onshore facility and the PSL set points were set to 15% below the lowest operating
pressures, the producers on the 10” South Pass 49 Pipeline System will not
automatically shut in with ruptures at the deepest operating point of the pipeline
(Milepost 23.1).

Page 21


Introduction

Time (hours) Pressure (psi Comment

1000 72

1100 103 Injected 141 barrels of water.
Stopped pumping. Aerial
surveillance started. No pressure
increase at SP 49 Onshore.

1145 - No slicks sighted

1200. 102

1300 100

1315 - No slicks sighted.

1400 99

1500 99

1530 - Oil observed coming to surface
in SP Block 38

1600 68

1700 69

1800 0

On October 5, divers confirmed that oil was coming from a depression on
the seafloor in the SP 38 area. The depression, located in a water depth of
110 feet, measured 8 feet in diameter and 6 feet deep. The leak location
was recorded at coordinates X = 107,143 and Y=2,656,428. Following
jetting operations on October 13, the pipeline was found approximately 20
feet below the mud line (see Attachment 5). The pipeline was found totally
parted, with the ends being approximately 3 to 4 feet apart and out of
alignment. The north end of the pipeline had a 20—foot mud plug, while the
south end of the pipeline had a 4foot mud plug. Shortly after pipeline

discovery, the ends of the pipeline were capped pending repair operations.

The pipeline repair entailed the installation of 10-inch ANSI 600 flexiforge

end connectors and the fabrication and installation of a spool piece

20


OCS Report
MMS 99-0053

Investigation of

Chevron Pipe Line Company
Pipeline Leak

South Pass Block 38
September 29, 1998

Gulf of Mexico
Off the Louisiana Coast

U.S. Department of the Interior
MVS Minerals Management Service
Gulf of Mexico OCS Regional Office


° If all four producers are ratably pumping simultaneously and a rupture occurred at the
SP 49 Onshore Facility riser at the water line (worst case rupture scenario), there are
two back pressure valve settings that will shutdown the producers on the 10” SP 49
pipeline. First a set pressure of 165 psi will start a chain of shutdowns on the system.
The results are in the following table.

Producer | Lowest Theoretical | Theoretical PSL setting | Theoretical Operating
Operating Pressure | based on 15% below Pressure for all four
for a single the lowest operating producers pumping
producer with 245 pressure if a 245 psi simultaneously with a
psi back pressure back pressure valve is rupture at SP 49
valve installed at SP 49 Onshore riser
(psi) Onshore. (psi)
(psi)
SP 45 147 125 63
MC 109 338 287 289
MC 20 158 134 219
SP.49 “A” 172 146 212

Table 3.50. Comparison of theoretical PSL settings with a 165 psi back pressure control valve installed at
SP 49 Onshore versus the operating pressure if all four producers are pumping with a rupture at the SP 49
Onshore facility riser at the waterline

SP 45 would shutdown on a PSL command first and the pressures at MC 109, MC
20 and SP 49 “A” would decrease to approximately 285 psi, 215 and 209 psi
respectively. MC 109 would shutdown on a PSL command and the pressures at
MC 20 and SP 49 “A” would decrease to 21 psi and 15 psi respectively and both
producers would shutdown on PSL.

A back pressure valve setting of 270 psi will shut down all producers on a PSL
command without waiting for other producers to shutdown and decrease the
operating pressure on the pipeline system. The results are in the following table.

Page 22



Attachment 1

a
-f
ea)
ot

UNITED STATES GOVERNMENT
MEMORANDUM

To: David Moore, Pipeline Section, Field Operations, GOM OCS Region (MS 5232)
Frank Torres, Pipeline Section, Field Operations, GOM OCS Region (MS 5232)
Mike Joseph, Surface Commingling and Production Measurement Section,
Production and Development (MS 5312)

From: Regional Director, Gulf of Mexico OCS Region (MS 5000)

Subject: Accident Investigation Panel

To confirm prior verbal communication, and pursuant to Minerals Management Service Manual,
Part 640, Chapter 3, Accident Investigations, you are hereby appointed to serve as the accident
investigation panel to investigate the break that occurred on or about September 28, 1998, in the
10-inch gas/oil pipeline, Segment No. 5625, Right-of-Way OCS-G 7561, permitted to Chevron
Pipeline Company and constructed between Platform A, South Pass Block 49, Lease OCS-G 2177,
and the Federal-State boundary in South Pass Block 27, Lease OCS-0693, off the Louisiana coast.
David Moore is designated as the panel chairman.

Please convene the panel as soon as possible and coordinate the investigation with the Department
of Transportation, Office of Pipeline Safety, and the U. S. Coast Guard.

Fas Chris C, Oynes

cc: 1401-0la (MS 5232)
MS 5000 Reading File

JRHennessey:amm: 10/27/98:acinvpnl.mem


Introduction

Incident Description — Pre-Hurricane Pipeline System Operations
During the latter part of September 1998, Hurricane Georges threatened oil
production and handling facilities in the Gulf of Mexico. With the imminent
impact of the Category 4 hurricane, operators of facilities that tied into the
CPL 10-inch pipeline began preparations to shut down facilities and
evacuate personnel. As part of the evacuation procedures, all facilities were

required to read meters manually and then to fax the readings to CPL.

On the afternoon of September 25, BP personnel stationed on MC 109 shut
down power at approximately 1400 hours, prior to departing the platform.
On the same day, OXY personnel followed a similar set of actions. In both
cases, termination of power resulted in the cessation of SCADA
communications with Chevron’s CSC. On September 26, Chevron CSC
lost SCADA communications with Taylor Energy Company’s MC 20
platform, which had also been shut down due to the impending storm.
While CUSA evacuated personnel from SP 49 during the same period, the
platform remained on production and was operated remotely by Chevron
Production (CPDN) staff located at the Gravier Control Center. The
platform was eventually shut in on the morning of September 27 because of
the loss of SCADA communications with the platform.

All facilities remained shut in through the remainder of September 27 and
the entire day of September 28 as Hurricane Georges passed through the
Gulf of Mexico as it moved northward to make eventual landfall in
Mississippi. Throughout this period, SCADA communications were
inoperative because of the lack of power at all platforms as well as at SP 49
Onshore.



Introduction

Following are basic production and platform data for each of the facilities
that deliver oil to CPL’s 10-inch transportation pipeline:
SP 49 MC20 MC 109 SP 45
Avg. Daily Oil Production (BOPD) 6,200 600 10,300 180

Avg. Daily Gas Production (mmscfd) 24.5 6 8.8 3
24-Hour Manned Facility? Yes Yes Yes = Yes
SCADA System? Yes Yes Yes = Yes

MC 20 connects to the SP 49 system via a 6-inch oil pipeline, 53,570 feet in
length (SN 7296), constructed in 1984; MC 109 connects to the SP 49
system via an 8—inch oil pipeline, 36,959 feet in length (SN 9347),
constructed in 1991; and SP 45 connects to the SP 49 system via a 4~inch
oil pipeline, 4,480 feet in length (SN 8738), constructed in 1989. SP 49 is
the originating point of the SP 49 pipeline system.

Oil delivered to the SP 49 pipeline system is flowed to a tank battery
referred to as SP 49 Onshore (see Attachment 3). The battery consists of
three tanks, each with a capacity of 5,000 barrels. One inch of height in the
three tanks combined equals 52 barrels. Only one of the tanks is equipped
with a gauge that allows visual confirmation of fluid height. Levels in the
tanks are maintained at five feet. When fluid height in the tanks reaches
eight feet, pumps automatically cut on in order to transfer the oil into the
onshore pipeline network. Operation of the pumps that lower fluid level can
be accomplished manually by an operator on site or remotely by an operator
stationed at Chevron’s Customer Service Center (CSC), located in Houston,
Texas. In no case, however, can pumps be started if the fluid level is below

five feet.


SS Chevron

Research and Technology

Richmond, California
January 14, 1999
Attachment 9

SOUTH PASS 49 CRUDE OIL PIPELINE
MATERIAL FAILURE ANALYSIS

Kevin Gaudet
Keith Bergeron

Summary
MATERIAL FAILURE:

A failure occurred in a 10” pipeline that carries crude oil from the SP49A platform to the SP 49 onshore tank
battery. The line had been shut-in upon approach of hurricane “Georges”. When the line was put back into service,
an oil slick was discovered and ultimately traced to a failure at a weld in the line. Failed sections of the line were
removed and sent to CRTC for analysis.

CAUSE OF FAILURE

The pipeline failed by propagation of a crack along the weld heat affected zone. A combination of high stresses
generated by a mudslide and low fracture toughness of the pipe resulted in a rapid catastrophic fracture.

Background

A failure occurred in a 10” pipeline that carries crude oil from the SP49A platform to the SP 49 onshore facility.
The line had been shut-in upon approach of hurricane “Georges”. After initial start-up, and subsequent pressure
tests of the pipeline, oil was detected on the surface and traced back to this line. The leak was located approximately
23 miles from the SP49A platform (7 miles from the onshore facility) in 110 ft. of water. The line was buried under
20 ft. of mud. The pipe had been completely severed at a butt weld in the line and the ends had separated by 3-4
feet.

The line is located in an area prone to mudslides and runs parallel to the prevailing slope of the sea bottom. After
the storm, a side scan sonar survey indicated a slide in the area. A depth of coverage survey of the line was
attempted, however, the survey was unsuccessful due to the mud composition. A six-foot section of the line
containing the failed weld was removed and sent to CRTC for analysis.

Fracture Surface Examination

For ease of explanation in describing the fracture surface, a schematic of the fracture surfaces is shown in Figures 1
& 2. The orientation of 0° was arbitrarily assigned to one of the weld buttons. If a downhill welding direction is
assumed (which is most common in pipeline welding), the 0° orientation would correspond to the bottom of the pipe
as oriented during welding. This orientation is shown in the upper left-hand corner of Figures 1 & 2. The 180°
oricntation would then correspond to the start of welding and 0° would be the stop. Note that this was not
necessarily the orientation of the pipe while in service. The numbers on the figures (98-377, etc) correspond to
metallographic samples taken from the pipe for further analysis.

C.N. Dykstal File: 04.15.05, 18.10, 70.33


Conclusions

Following a thorough review of relevant information related to the oil spill
that occurred in South Pass Block 38, the investigation panel arrived at the

following conclusions:

1. The damage to the pipeline occurred as a result of a natural hazard,
specifically a mudslide that was precipitated by a hurricane.

2. The most probable total volume of oil that was spilled during the
primary and secondary releases was 8,212 barrels.

3. Deviations from established other-than-normal startup operating
procedures contributed to the failure to identify the pipeline leak
promptly.

4. Poor communications during system start-up contributed to the failure
to identify the pipeline leak promptly.

5. Responsible personnel failed to recognize, verify, or take appropriate
action upon critical indicators that pointed to a significant system
imbalance during post-hurricane startup.

6. The primary leak detection system, i.e.. PSLs, was ineffective in sensing
the pipeline leak because of the negligible pressure drop measured at the

pressure sensors.

39


3.3 Pipeline Rupture at MC 109 Tie-In (Milepost 27.1)

At the MC 109 tie-in, the water depth is approximately 640 fsw. The hydrostatic pressure
at this water depth is approximately 288 psi.

For this rupture location, SP 45 is located downstream of the Jeak site and MC. 109, MC
20 and SP 49”A” is located upstream of the leak site.

Effects of Pumping Ratably
The following table summarizes a theoretical PSL setting based upon the operating

pressures from Table 3.0 and if a single producer, pumping ratably, would shutdown on a
PSL command with a pipeline rupture at the MC 109 tie-in. (Milepost 27.1 and -640
fsw).

Producer Theoretical PSL setting Operating PSL
based on 15% below the Pressure protection
operating pressure of (psi)
Table 3.0.
(psi)

SP 45 See -1 Yes
MC 109 147 102 Yes
MC 20 See 30 No
SP 49 “A” 6 25 No

Table 3.30. Comparison of theoretical PSL setting vs. operating pressure for a single producer
pumping ratably with a pipeline rupture at the MC 109 tie-in (Milepost 27.1 and -640 fsw).
*** 5 psi is the lowest PSL setting allowed by the MMS

Theoretically, with a ratable system, MC 20 and SP 49”A”, pumping as a single producer,
would not shutdown on a PSL command.

Effects of Ratable Pumping and Installing a 60 psi Back Pressure Valve

The following table summarizes a theoretical PSL setting based upon the lowest
operating pressures from Table 3.01 and if a single producer, pumping ratably, would
shutdown on a PSL command with a pipeline rupture at the MC 109 tie-in (Milepost 27.1
and-640 fsw).

Page 19


Panel Investigation and Findings

All of these factors make spill volume determination based on visual
observation somewhat problematic, and often, as in this case, can result in

underestimation of the severity of the spill.

Oil Spill Volume Determination
Calculation of the exact amount of oil released during the post-hurricane
startup phase of the SP 49 pipeline system is not feasible. A review of
overages and shortages during the previous 12-month period shows major
fluctuations in the system, thus making application of factors to this event
irrelevant. For example, July showed a shortage of 5,683 barrels, while
August showed an overage of 6,742 barrels, indicating a tendency for
significant variances to balance out over time, but only when production

levels are essentially the same.

‘When 6—month running averages of the overages and shortages for 1998 are
calculated, including the reported 9,677 barrel shortage that occurred in
September, variances range from -76 to -1,573 barrels. A review of the data
for the same time period, assuming that September showed a shortage of 131
barrels (the 11—month average excluding the September reported value),
produced variances ranging from +302 to -1,216 barrels. The reported
shortage figure of 9,677 barrels for September could therefore range from
8,461 to 9,979 barrels using these averaged figures, if production levels had
remained constant, which they did not. Still, the figures generally correlate
to the volume calculated by CPL and help establish the upper-end limits of oil

loss.

A gross approximation of a spill volume has been calculated below, given
review of the production tickets from affected platforms, consideration of

startup practices, timing of events, and estimation of pipeline residual leakage

27


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Panel Investigation and Findings

versus observed oil volume and the time that passed before released oil
reached the surface pose a number of questions for which general theories

are posited and scientific fact are presented below.

It has been observed that not all oil that is released from subsea locations
comes to the surface in the immediately vicinity of the release point. Studies
have shown that oil “plumes” can remain in the water column for periods of
time without surfacing. Additionally, it has been found that plumes do not
necessarily move in the same direction as a surface slick because of opposing

water currents or eddies near river outflows.

After oil that is released from a subsea location reaches the surface of the
water, natural forces such as gravity and surface tension immediately work to
cause the oil to form a thin layer on the water. This thinning of the oil then
facilitates the commencement of other dispersive processes, such as
evaporation, dissolution, emulsification, chemical reaction, biological

degradation, and formation of tar lumps.

As oil begins to disperse and to “weather,” efforts to obtain an accurate
estimate of the spill volume are impacted. Light hydrocarbons can rapidly
evaporate, oxidize, or be mixed with seawater and dispersed in the water
column. Heavier hydrocarbons can weather in much the same manner and
can also form emulsions or tar lumps. Surface winds and chop can break oil
into streamers and tar balls which are difficult to identify during aerial
surveillance because of size, reflection of light, and a process called over-

washing.

26


* ata back pressure of 60 psi, all points in the system are protected by PSL’s when a
single producer is on-line; however, the system is not always protected when multiple
producers are online.

* ata back pressure of 525 psi, all points in the system are protected by PSL’s even if
all producers are on-line.

ANALYTICAL APPROACH

The hydraulic analysis of the 10” South Pass 49 (SP 49) Pipeline System included the
following:

Operating Scenarios

¢ Producers pumping at current pump rates.
¢ Producers pumping ratably.

Rupture Locations

Determine the operating pressures of the producers for the following rupture locations
using the above operating scenario:

¢ Pipeline system in the current configuration.

¢ Rupture in the 10” pipeline at Milepost 6.5 (SP 38 area).

° Rupture in the 10” pipeline at Milepost 23.1 in 780 feet of seawater (deepest

point).

¢ Rupture in the 10” pipeline at the MC 109 tie-in (Milepost 27.1 in 640 feet of
seawater).

e Rupture in the 10” pipeline at the MC 20 tie-in (Milepost 27.9 in 540 feet of
seawater).

e Rupture in the 10” SP 49 Pipeline riser at the SP 49 Onshore Facility.
PSL Settings

Determine if the following PSL settings will shutdown the producers at each rupture

location.

¢ Current PSL setting.

¢ Theoretical pressure safety low (PSL) settings for each producer based upon 15%
below the lowest calculated operating pressure of each producer pumping
individually at current pump rates.

e Theoretical PSL setting for each producer based upon 15% below the lowest
calculated operating pressure of each producer pumping individually at current
pumping rates and if a 60 psi back pressure valve is installed at the SP 49 Onshore
Facility.

Page 2


Investigation and Report

On January 15, 1999, the panel investigation chairman met with two
representatives of CPL to confirm data provided in the CPL spill report
through review of a time line analysis prepared by the panel chairman from
available event data. During the discussions, CPL staff provided additional
insight into pipeline and supervisory control and data acquisition (SCADA)
operations, problems with communication during the spill, and tank gauging

practices.

At that time, CPL staff provided written responses to questions posed by the
investigation panel. Answers to each question and associated data provided
to support answers were reviewed for completeness and clarity. Subsequent

to the meeting, answers were forwarded to all panel members for review.

On January 22, 1999, the Chevron Customer Service Center (CSC) E-
mailed answers to questions posed during the meeting between MMS and
CPL personnel on January 15. An additional request for information was
forwarded to CSC on January 25, 1999, following review of Chevron’s
responses to the original MMS data request. CSC’s responses were

received by facsimile on January 27.

The investigation panel convened on Wednesday, January 27, to review all
data collected during the discovery portion of the investigation. The panel
began the process of reviewing, editing, and approving portions of the
report that had been prepared by the panel chairman. The panel also
collectively discussed the preparation of the remaining portions of the report
and developed draft report conclusions and recommendations. All panel

members were present.

On Tuesday, March 2, additional questions on issues ranging from safety

system operations to established post-hurricane operational procedures were

3


Introduction

Possible Oil Spill Volume

Initial estimates of the oil spill volume ranged from 850 to 8,500 barrels,
based upon visual observations and worst-case estimates. On October 4, the
Unified Command published a report indicating the spill size to be 3,690
barrels, based primarily upon visual estimates of slick size. Estimates from
BP from mass balance calculations indicated a discrepancy of approximately
7,500 barrels. The only consistency in spill volume estimates was their

inconsistency.

During their post-incident investigation, CPL provided the following data to
support their estimate of the total volume of oil spilled during the incident:

Gross
Volume Description Facility Volume (Bbls
a. Volume pumped after startup MC 109 7,549
SP 45 263
b. Volume of second release 85
c. Volume to fill lines to pressure
test MC 109 15
SP 45 1
MC 20 9
SP 49 97

d. Volume recovered to tank when
pressure test bled to zero SP 49 Onshore (61)

TOTAL 7,958

An initial estimate by CSC on October 9 of the spilled volume indicated that
MC 109 had pumped 7,765 barrels since the hurricane, and that SP 45 had
pumped a total of 301 barrels. Using these figures in conjunction with the

volume of the second release and oil recovered during the pressure test

17


Producer | Theoretical PSL setting Operating PSL protection
based on 15% below Pressure
the lowest operating (psi)
pressure of Table 3.01.
(psi)
SP 45 36 28 Yes
MC 109 198 102 Yes
MC 20 45 30 Yes
SP 49 “A” 57 25 Yes

Table 3.31. Comparison of theoretical PSL settings with a 60 psi back pressure control valve
installed at SP 49 Onshore versus the operating pressure of a single producer pumping ratably with
arupture at MC 109 tie-in (Milepost 27.1 and -640 fsw).

Theoretically, installing a 60 psi back pressure valve at SP 49 Onshore would provide
PSL protection to a single producer operating on the upstream and downstream side of
the rupture. Also, if MC 109, MC 20 and SP 49”A” are pumping simultaneously on the
upstream side of the rupture their pressures would be about 102 psi, 32 psi and 25 psi
respectively. Therefore, all three producers would shutdown on PSL.

3.4 Pipeline Rupture at MC 20 Tie-In (Milepost 27.9)

At the MC 20 tie-in, the water depth is approximately 540 fsw. The hydrostatic pressure
at this water depth is approximately 243 psi.

For this rupture location, SP 45 and MC 109 is located downstream of the leak site and
MC 20 and SP 49” A” is located upstream of the leak site.

Effects of Pumping Ratably
The following table summarizes a theoretical PSL setting based upon the operating

pressures from Table 3.0 and if a single producer, pumping ratably, would shutdown on a
PSL command with a pipeline rupture at the MC 20 tie-in. (Milepost 27.9 and -540 fsw).

Producer Theoretical PSL setting Operating PSL
based on 15% below the Pressure protection
operating pressure of (psi)
Table 3.0.
(psi)

SP 45 Piieial 4 Yes
MC 109 147 89 Yes
MC 20 See 22 No
SP 49 “A” 6 16 No

Table 3.40. Comparison of theoretical PSL setting vs. operating pressure for a single producer
pumping ratably with a pipeline rupture at the MC 109 tie-in (Milepost 27.9 and -540 fsw).
** 5 psi is the lowest PSL setting allowed by the MMS

Page 20


CHEVRON 10" PIPELINE REPAIR -- SOUTH PASS 38 -- OCTOBER 1998

REPAIR SPOOLPIECE (10"X 16’ 5-1/16") RIGGING SPOOLPIECE



The following table summarizes a theoretical PSL setting based upon the operating
pressures from Table 3.01 and if a single producer, pumping ratably, would shutdown on
a PSL command with a pipeline rupture at Milepost 6.5 (SP 38 area).

Producer | Theoretical PSL setting | Operating | PSL protection
based on 15% below Pressure
the operating pressure (psi)
of Table 3.01.
(psi)
SP. 45 36 -15 Yes
MC 109 198 150 Yes
MC 20 45 -5 Yes
SP 49 “A” ST 5 Yes

Table 3.12. Comparison of theoretical PSL settings with a 60 psi back pressure control valve
installed at SP 49 Onshore versus the operating pressure of a single producer pumping ratably with
a rupture at Milepost 6.5 (SP 38 area).

Theoretically, a ratable system and installing a 60 psi back pressure valve at SP 49
Onshore would provide PSL protection a single producer pumping into the 10” pipeline.
However, if MC 109 and SP 49 “A” were pumping simultaneously, they would not
shutdown on a PSL command until one producer completed their normal pumping cycle.

3.2 Pipeline Rupture at Greatest Depth of the 10” Pipeline

The greatest water depth the 10” SP 49 pipeline operates in is approximately 780 fsw and
occurs at Milepost 23.1. The hydrostatic pressure at this water depth is approximately
351 psi.

In the following scenarios, SP 45 is located downstream of the leak site and MC 109, MC
20 and SP 49”A” is located upstream of the leak site.

Effects of Ratable Pumping

The following table summarizes a theoretical PSL setting based upon the operating
pressures from Table 3.0 and if a single producer, pumping ratably, would shutdown on a
PSL command with a pipeline rupture at Milepost 23.1 (-780 fsw).

Page 17


Producer Theoretical PSL setting Operating Pressure PSL
based on 15% below the | with a rupture at the | protection
lowest operating pressure SP 49 Onshore
if a 270 psi back pressure facility (all 4
valve is installed at SP 49 | producers pumping)
Onshore. (psi)
(psi)
SP 45 214 63 Yes
MC 109 375 289 Yes
MC 20 223 219 Yes
SP 49 “A” 235 212 Yes

Table 3.51. Comparison of theoretical PSL settings with a 270 psi back pressure control valve
installed at SP 49 Onshore versus the operating pressure if all four producers are pumping with a
rupture at the SP 49 Onshore facility riser at the waterline.

The installation of a back pressure valve set at 165 psi or 270 psi will shutdown
the 10” pipeline if all four producers are operating and a pipeline rupture occurred
on the riser at SP 49 Onshore above the waterline.

4.0 SYSTEM RECOMMENDATION

The recommendation for safely operating the 10” SP 49 Pipeline can be obtained as

follows:

¢ Keep the producers at current pumping rates and have the producers reset their PSL
settings to 15% below their respective operating pressures when pumping. Although,
the change in PSL setting will not shutdown all the producers at the pipeline rupture
locations studied, the change will increase the number of producers that will
shutdown versus the current PSL settings.

° Configure the monitored SCADA points (offshore LACT meters SP 49 Onshore tank
levels and SP 49 Onshore meters) to provide line balance information that can be
trended. SCADA monitoring will be able to detect a leak on the system better than
the capabilities of the PSL’s for a leak at or near the SP 49 Onshore Facility. Chevron
Pipe Line Company has initiated the work to provide our Customer Service Center
controllers with this capability for the SP 49 Pipeline System.

Page 23


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Panel Investigation and Findings

First, a pressure buildup should have been observed at SP 49 Onshore
during the test. However, during an inspection of a pig trap located on SP
49 Onshore on October 1, it was discovered that the trap contained an
8-inch and a 10-inch utility pig and approximately 200 pounds of wax,
which probably account for the lack of pressure at SP 49 Onshore.

During normal operations, MC 109 runs their 8-inch pig each week on
Monday and SP 49 runs their 10-inch pig on Tuesday. This is done to
ensure that the 10-inch pig will push the 8—inch pig into the trap at SP 49
Onshore. Operations personnel failed to recall that pigs had been run prior

to the cessation of operations before the hurricane.

During the initial pressure test, gas was used as the test medium. Pressure
was held at 165 psi for two hours at SP 49. It is hypothesized that, given
the compressibility of gas, the volume of fluid in the pipeline, the depth of
the pipeline, and the relative depth of the leak location, that the initial test
pressure was inadequate. The test verified the integrity of the riser of SP 49
but was of insufficient pressure to push fluids through the pipeline system to

the rupture point.

Analytical Pipeline Leak Model

Settings on PSLs to detect pipeline leaks are established according to MMS
guidelines, which require a pressure setting of 15 percent below the normal
operating pressure but no lower than 5 psi. Theoretically, pressure losses in
the pipeline resulting from a breach in line integrity should be sensed by the
PSLs at the producing facilities, and shutdown valves should be activated to
stop fluid flow into the pipeline. It has long been assumed that catastrophic
pipeline failures would produce sufficient pressure losses to trip the PSLs.

Empirical evidence, however, has shown that the pressure loss from a minor

34


Producer | Theoretical PSL setting Operating PSL protection
based on 15% below Pressure
the lowest operating (psi)
pressure of Table 2.01.
(psi)
SP. 45 43 25 Yes
MC 109 198 93 Yes
MC 20 94 70 Yes
SP.49 “A” 128 23 Yes

Table 2.42. Comparison of theoretical PSL settings with a 60 psi back pressure control valve
installed at SP 49 Onshore versus the operating pressure of a single producer with a rupture at the
MC 20 tie-in (Milepost 27.9 and -540 fsw).

Theoretically, installing a 60 psi back pressure valve at SP 49 Onshore would provide
PSL protection to all producers pumping as single units on both the upstream and
downstream side of the rupture. Also, if SP 45 and MC 109 were pumping
simultaneously on the downstream side of the rupture, their pressures would be about 30
psi and 94 psi respectively. Both producers would shut down on PSL. If MC 20 and SP
49”A” were pumping simultaneously on the upstream side of the rupture, there pressures
would be approximately 70 psi and 23 psi respectively; therefore both producers would
shutdown on PSL.

2.5 Conclusions for Section 2

¢ The current PSL settings for each of the producers do not automatically shut-in flow
on the 10” SP 49 Pipeline System for a pipeline rupture at Milepost 6.5, Milepost
23.1, Milepost 27.1 and Milepost 27.9. The current PSL settings for SP 45, MC 109
and MC 20 may provide protection to the lateral pipelines if a rupture were to occur
close to their respective platforms. Also, current PSL setting for SP 49 “A” may
shutdown SP 49 “A” if a pipeline rupture were to occur close to the platform.

¢ Changing the PSL settings for each of the producers to 15% below the lowest
operating pressure as calculated by individual pumping rates does not automatically
shut-in flow on the 10” SP 49 Pipeline System for a pipeline rupture at Milepost 6.5,
Milepost 23.1, Milepost 27.1 and Milepost 27.9.

¢ The installation of a back pressure valve at the South Pass 49 Onshore facility set at
60 psi and changing the PSL levels to 15% below the lowest operating pressures,
automatically shuts-in flow on the 10” South Pass 49 Pipeline System at current
pumping rates for an operating pumping as a single producer. However, as noted in
Section 2.1, Pipeline Rupture at Milepost 6.5, if multiple producers are pumping
simultaneously, they will not shutdown on PSL until one of the producers completed
their normal pumping cycle.

Page 13


Panel Investigation and Findings

pipeline leak is inadequate to reduce the pipeline operating pressure below

the PSL setting, allowing the leak to go undetected.

The PSL settings for SP 45, MC 109, MC 20, and SP 49 A during post-
hurricane startup were 20 psi, 46 psi, 10 psi, and 5 psi, respectively. At
these approved settings neither of the two producers that were brought back
on stream (SP 45 and MC 109) shut in due to low pressure, even though the
SP 49 pipeline was completely parted and the platforms were effectively
pumping into an open-ended pipeline buried approximately 20 feet below
the seafloor.

To analyze the SP 49 pipeline system hydraulics and safety system
operations, CPL used a pipeline model to simulate the system under various
configurations. The primary objective of the analysis was to determine why
the PSLs had failed to shut in the producing platforms. The simulations
involved review of the effectiveness of PSLs on the basis of pipeline
ruptures at different locations, operating pressures, pumping rates,
groupings of producers pumping at the same time, water depths, and
theoretical back pressures at SP 49 Onshore. The report, “South Pass 49
Pipeline System Pressure Safety Low Setting Evaluation,” may be found in
its entirety in Appendix 11. An example of model results follows.

35


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Panel Investigation and Findings

Investigated Aspects

The investigation panel members reviewed and analyzed the following
aspects of the pipeline leak incident:

> The cause of the pipeline failure

id System measurement balance data

» Factors affecting the appearance and observation of leaked oil
» The most probable oil spill volume

» Startup chronology and procedures

» Leak detection methodologies

» Modeling of the pipeline system’s safety devices

Cause of Pipeline Failure

As noted earlier, the 10-inch pipeline suffered a rapid catastrophic failure.
The failure is assumed to have occurred between 0200 hours on

September 27, the time at which SP 49 was shut down, and at 1530 hours on
September 29, the time at which SP 45 was allowed to resume production.
The failure was due to high stress induced by a mudslide, coupled with a low
pipe fracture toughness, and occurred along a weld that joined two lengths of
pipe.

A review of historical pipeline repair records shows that this is the first
reported occurrence of a mudslide of such magnitude that the SP 49 pipeline
system was subjected to sufficient forces to result in damage. With a
reported seafloor slope of approximately two to three feet per 500-foot
distance in this SP location, seafloor movement would not appear to be a
problem. Still, a survey conducted shortly after Hurricane Georges shows
that, in addition to the mudslide that parted the 10-inch pipeline, a number of
other mass movements had also occurred in the same vicinity in the SP area,

at least one of which crossed over SN 5625 (see Attachment 10).

23


Attachment 7
CHEVRON 10" PIPELINE REPAIR -- SOUTH PASS 38 — OCTOBER 1998

BIMS FORGING TOOL BIMS FORGING TOOL

BIMS FORGING TOOL BIMS END CONNECTORS.



ORIGINAL - RED
2/2994
" Attachment 11
Chevron Pipe Line Company
South Pass 49 Pipeline System

Pressure Safety Low Setting Evaluation
March 25, 1999

This hydraulic analysis was performed by Chevron Pipe Line Company in response to the
pipeline failure that occurred in the South Pass 38 area near Milepost 6.5 on the 10”
South Pass 49 Pipeline System. The desired outcome of the analysis is to determine why
the Pressure Safety Low (PSL) settings for British Petroleum’s Mississippi Canyon 109
Platform and Occidental’s South Pass 45 platform did not activate the shutdown valves
(SDV’s) on the respective platforms.

Other desired outcomes of the hydraulic analysis are:
Determine the theoretical operating pressures for each producer.

Investigate the effectiveness of the actual PSL settings if the pipeline were to
rupture at predetermined locations.

Investigate the effectiveness of calculated PSL settings for the producers if the
pipeline ruptured at predetermined locations.

Investigate the pressure increase and corresponding calculated PSL settings for the
producers if CPL installed a 60 psi back pressure valve at South Pass 49 Onshore
and the pipeline ruptured at predetermined locations.

SUMMARY OF CONCLUSIONS

Current PSL and Pump Rate Configuration

© The current PSL settings for each of the producers will not automatically shut in-flow
to the 10” SP 49 Pipeline System for a rupture at all points in the system.

Revised PSL Setting at Current Pump Rate Configuration

If the PSL setting for each producer is changed to point that is 15% below the lowest
operating pressure as calculated by individual pumping rates, then:

© producers will not shut-in for a pipeline rupture at all points in the system.

If, in addition to changing the PSL settings, a back pressure valve is installed at the South
Pass 49 Onshore Facility, then:

Page 1


Table of Contents - continued

Attachments 220001 en
1. Memorandum Establishing Accident Investigation Panel
2. West Bay Pipeline System
3. 10" South Pass 49 Pipeline System
4. October ‘98 Chevron Pipeline Oil Spill Environmental Impact and Response

Evaluation
5. Chevron 10" Pipeline Repair/South Pass 38 — Pipeline Profile Information as of
October 15, 1998
Spool Piece Design
Photographs - Pipeline Repair
Photographs ~ Pipeline Damage
South Pass 49 Crude Oil Pipeline Material Failure Analysis
Sidescan Sonar Survey — Mass Movement Features
Chevron Pipe Line Company — South Pass 49 Pipeline System ~ Pressure Safety
Low Setting Evaluation ~ March 25, 1999

rege ena

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Attachments

“a ek YON

a

11.

Memorandum Establishing Accident Investigation Panel

West Bay Pipeline System

10" South Pass 49 Pipeline System

October ‘98 Chevron Pipeline Oil Spill Environmental Impact and Response Evaluation
Chevron 10" Pipeline Repair/South Pass 38 — Pipeline Profile Information as of
October 15, 1998

Spool Piece Design

Photographs — Pipeline Repair

Photographs — Pipeline Damage

South Pass 49 Crude Oil Pipeline Material Failure Analysis

Sidescan Sonar Survey — Mass Movement Features

Chevron Pipe Line Company — South Pass 49 Pipeline System - Pressure Safety
Low Setting Evaluation — March 25, 1999

42


Recommendations

The initial oil spill that occurred as a result of the rupture of the SP 49 system

pipeline during the burricane was unforeseeable and unavoidable. The

additional loss of oil into the environment during system startup, however,

could have been prevented had information on mudslide risks, post-hurricane

startup procedures, and safety system inadequacies been available to the

pipeline operating company.

As a result of the findings and conclusions of this investigation panel, the

following recommendations, designed to prevent a reoccurrence of an

incident similar to the SP 38 spill, are offered for approval and immediate

implementation by the respective agencies or companies noted therein.

The MMS should undertake a study to identify areas throughout the
Gulf of Mexico where pipeline damage has occurred as a result of
mudslides and should make the data available to interested parties.

The MMS Gulf of Mexico Region should advise operators of pipelines
in mudslide-prone areas to review and, where appropriate, revise post-
hurricane startup procedures to address additional steps that will be

taken to ensure pipeline integrity prior to resumption of operations

The MMS should advise pipeline operators of the need to assess the
effectiveness of PSLs in pipeline leak detection and the need for
consideration of alternate and/or supplementary leak detection methods
if PSLs are deemed potentially inadequate on individual pipelines and/or
pipeline networks.

The MMS should undertake a study to determine the effectiveness of
PSLs on pipelines under various pipeline operating conditions.

40


2.0 Operating Scenario - Current Pumping Rates

The following table summarizes the theoretical operating pressure if a single producer
were pumping into the onshore storage tanks on the 10” SP 49 pipeline at current
pumping rates. This would give the lowest operating pressure for each producer.
However, it should be noted that the producer’s daily production levels dictate the
pumping schedule and only one producer pumping at a time is not the normal operation
for the pipeline system. Based upon current production levels, MC 109 is pumping the
majority of a 24 hour day, SP 49 “A” pumps on an intermittent schedule and MC 20 and
SP 45 pump approximately two — four times a day. The operating pressure for each
producer is significantly higher than the results below when two, three or all four
producers are pumping.

Producer Lowest Theoretical
Operating Pressure
(psi)
SP 45 ~10.3*
MC 109 173
MC 20 50
SP 49 “A” 90
Table 2.0. Theoretical operating pressure for a single producer pumping into tankage at
SP 49 Onshore.

* In theory, SP 45 does not pump at a rate that will generate head loss in the system to
create positive pressure at SP 45.

The following table summarizes the theoretical operating pressure if a single producer
were pumping into the onshore storage tanks and a 60 psi back pressure valve was

installed at the SP 49 Onshore Facility. This would be the lowest operating pressure for
each producer.

Producer Lowest Theoretical
Operating Pressure
(psi)
SP 45 50
MC 109 233
MC 20 110
SP 49 “A” 150

Table 2.01. Theoretical operating pressure for a single producer pumping into tankage

with a 60 psi back pressure valve installed at SP 49 Onshore.

Page 4



Introduction

platform did not resume pumping until approximately 2200 hours on

September 29.

Neither CSC nor the Chevron FTL received verbal confirmation from BP
that oil was being pumped into the SP 49 pipeline system. Although
SCADA communications were initially restored with MC 109 at
approximately 1000 hours, the CSC lost SCADA communications with MC
109 at approximately 2000 hours.

Throughout startup, the SCADA communications systems at CSC which,
when operational, can monitor pressures and flow rates at SP 49, MC 20,
MC 109, SP 45, and SP 49 Onshore, were working intermittently. Hard line
communications between all facilities were also intermittent because of
hurricane damage. As a result, the CSC was unable to monitor flow rates
continuously at the facilities flowing into the SP 49 system or at the SP 49
Onshore tank battery, or to maintain constant voice communication to verify
operations. The only means of voice communication between CSC and
personnel at MC 109 was a cellular phone on MC 109. This, too, became
inoperative during the evening of September 29 because of battery failure.

To monitor production, given the problems being experienced with both
SCADA and hard lines, the Chevron FTL had dispatched a gauger to SP 49
Onshore to hand-gauge the tanks. Per instructions, the gauger recorded
and reported field measurements to CSC staff for comparison with available
SCADA readings throughout the evening of September 29 and the morning
of September 30.

Both MC 109 and SP 45 remained on production throughout the morning of
September 30. It was not until 0900 hours, however, that CSC became

10


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Page 3

South Pass 49 Pipeline
Pipe B

Figure 2 Schematic of pipe “B” side of fracture surface indicating location of fracture, secondary cracks,
and metallographic samples.

‘The fracture occurred primarily along the weld heat affected zones (HAZ). Approximately 50% of the fracture
surface propagated along the pipe “B” HAZ, transitioned across the weld, and then followed the pipe “A” HAZ
(Figures | & 2), The surfaces were covered with rust in the as-received condition. Upon light chemical cleaning to
temove the corrosion products, no obvious initiation site or evidence of a preexisting flaw was apparent. Diameter
measurements at the fracture revealed a 0.125 in. difference between major and minor dimensions. Appreciable
plastic deformation at the failure was not apparent. Metallographic cross sections indicated that crack propagation

C.N. Dykstal File: 04.15.05, 18.10, 70.33


Introduction

production because of apparent line shortages. On October 1, at 0900
hours, as a result of CPL’s inability to determine the cause of the line
shortage, BP reported the spill to the National Response Center (NRC) on
the basis that MC 109 had pumped approximately 7,500 barrels of oil
unaccounted for by CPL. At 1030 hours, BP activated their spill

management team to respond to the spill.

Prior to BP’s reporting of the spill, there had been no reports of sightings of
oil in or around MC 109 or along the SP 49 pipeline route. Shortly after the
report, a USCG surveillance helicopter flight located a major oil slick in the
MC/SP vicinity.

For a review of response actions taken by BP during the initial phases of the
spill, see the report “Incident: South Pass Spill Volumes 1-III,” which is part
of the MMS investigative files. MMS conducted an investigation of the BP
response, which can be found in the report “October ‘98 Chevron Pipeline
Oil Spill Environmental Impact and Response Evaluation” (see

Attachment 4).

Oil Spill Observation Reports
During the initial phases of startup of the SP 49 system, CPL conducted a
number of overflights to look for signs of oil from their pipeline. After
SCADA and tank level readings pointed to a significant oil loss, BP also
initiated overflights of their pipeline. The Morgan City Marine Safety Office
(MSO) also began overflights in the SP/MC areas following notification by
the NRC of a possible major leak. Available overflight data are summarized
below, while a map showing locations of reported spills can be found in

Attachment 2.

12


Table of Contents

Abbreviations and Acronyms ................06. 000 cece eee cee ee iv
Investigation and Report

Authority 00 eee eee eee ee 1
Procedures... 22... eect eee 2

Introduction

Background ... 0.22.2.
Incident Description - Pre-Hurricane Pipeline System Operations . an
Incident Description - Post-Hurricane Startup Operations .................-.--.
Oil Spill Observation Reports .... 0.00.00. 002

Analysis of System Receipts and Deliveries and Leak Detection :
Possible Oil Spill Volume... 2... 0022.
Leak Source Identification... 2... eee
Failure Analysis 2.02.22

Panel Investigation and Findings

Investigated Aspects 2.2.00 23

Cause of Pipeline Failure 2.2... 23

System Measurement Balance ... 24

Factors Affecting the Surface Appearance and Observation of Oil ..............- 25

Oil Spill Volume Determination .............00002..000002 200002005

Startup Procedures and Chronology .

Leak Detection Methodology ...... 20.00.0002 eee

Analytical Pipeline Leak Model 2.0.0... 0
Conclusions ....... 6... nce eee 39
Recommendations ............ 2.000.000. 40


Panel Investigation and Findings

the pipeline leak location to the mouth of the Mississippi River, it is argued
that during the initial spill riverine currents pushed the oil phume to deeper
water, At the time of its initial discovery the slick was described as oriented

from northeast to southwest.

During the secondary spill that occurred during the pressure—testing
sequence, surfacing and the subsequent sighting of oil were as expected,
near the actual leak location in SP 38. Within four hours of the initiation of
the pressure test, oil was sighted through aerial surveillance. This finding
disputes the previous theory on subsea oil plume movement; however, such
observations should be considered while attempting to sight spills from

specific pipeline systems.

Standup tests of pipeline systems are another method used to ascertain if a
system can maintain a static pressure for a given length of time. After the
hurricane, CPL staff made the determination that a standup test did not have
to be conducted on the offshore component of the pipeline system because
SCADA was operational at the time of their decision. Even though SCADA
operations malfunctioned early in the startup process, the decision to

conduct a standup test was not revisited.

During the post-spill pipeline leak identification phase, pressure tests were
conducted on the pipeline system from SP 49 to SP 49 Onshore.
Throughout the initial pressure test, pressure at SP 49 Onshore remained at
0 psi, pressure on the pipeline appeared stable, and no slicks were observed.
Several factors contributed to the appearance that the pipeline system was

intact.

33


¢ [fall four producers are pumping simultaneously and a rupture occurred at the SP 49
Onshore Facility riser at the water line (worst case rupture scenario), there are two
back pressure valve settings that will shutdown the producers on the 10” SP 49
pipeline. First a set pressure of 410 psi will start a chain of shutdowns on the system.
The results are in the following table.

Producer | Lowest Theoretical | Theoretical PSL setting | Theoretical Operating
Operating Pressure | based on 15% below Pressure for all four
for a single the lowest operating producers pumping
producer with 410 pressure if a 410 psi simultaneously with a
psi back pressure back pressure valve is rupture at SP 49
valve installed at SP 49 Onshore riser
(psi) Onshore. (psi)
(psi)
SP 45 400 340 157
MC 109 583 495 506
MC 20 460 391 488
SP 49 “A” 500 425 441

Table 2.50. Comparison of theoretical PSL settings with a 410 psi back pressure control valve installed at
SP 49 Onshore versus the operating pressure if all four producers are pumping with a rupture at the SP 49
Onshore facility riser at the waterline

SP 45 would shutdown on a PSL command first and the pressures at MC 109, MC
20 and SP 49 “A” would decrease to approximately 490 psi, 472 and 425 psi
respectively. MC 109 and SP 49 “A” would shutdown on a PSL command and
the pressures MC 20 would decrease and shutdown on PSL.

A back pressure valve setting of 525 psi will shut down all producers on a PSL
command without waiting for other producers to shutdown and decrease the
operating pressure on the pipeline system. The results are in the following table.

Producer Theoretical PSL setting Operating Pressure PSL
based on 15% below the | with a rupture at the | protection
lowest operating pressure SP 49 Onshore
if a 525 psi back pressure facility (all 4
valve is installed at SP 49 | producers pumping)
Onshore. (psi)
(psi)
SP 45 437 157 Yes
MC 109 594 506 Yes
MC 20 488 488 Yes
SP 49 “A” 522 441 Yes

Table 2.51. Comparison of theoretical PSL settings with a 525 psi back pressure control valve
installed at SP 49 Onshore versus the operating pressure if all four producers are pumping with a
rupture at the SP 49 Onshore facility riser at the waterline.

Page 14



Introduction

Failure Analysis

16 feet 5 1/16 inches in length (see Attachment 6). Photographs of the
surface preparations for the pipeline repair can be found in Attachment 7.

When pipeline SN 5625 was installed in 1980, MMS regulations required
the pipeline (at the leak location) to be buried a minimum of 3 feet below the
mud line. On October 5, during attempts to locate the pipeline leak
location, divers found the pipeline to be buried approximately 20 feet below
the mud line, indicating that a subsea mudslide had occurred. The pipeline
was found completely parted, with pipe ends separated by approximately 3
to 4 feet and out of alignment.

Visual inspection of the pipeline rupture point revealed total failure of the
pipeline where two pipeline sections had been joined by welding (see
Attachment 8). To ascertain the cause of failure, a 6-foot section of pipe
that contained the failure was cut from the pipeline by CPL and was
forwarded to the Chevron Research and Technology Center (CRTC) for
analysis.

On January 14, 1999, CRTC forwarded a report entitled “South Pass Crude
Oil Pipeline — Material Failure Analysis,” which detailed results of visual
inspections of the failure surfaces and metallographic testing (see
Attachment 9). The CRTC scientists determined that “the pipeline failed by
propagation of a crack along the weld heat affected zone (HAZ). A
combination of high stress generated by a mudslide and low fracture
toughness of the pipe resulted in a rapid catastrophic fracture.”

Both ends of the failed pipeline section contained a primary fracture along
their HAZ that transitioned through the weld to the HAZ of the adjoining

21


OCS Report
MMS 99-0053

Investigation of

Chevron Pipe Line Company
Pipeline Leak

South Pass Block 38
September 29, 1998

Gulf of Mexico
Off the Louisiana Coast

David M. Moore - MMS
Frank Torres - MMS

Mike Joseph - MMS

Buddy Sheets - USDOT
LCDR George Butler - USCG

U.S. Department of the Interior
Minerals Management Service New Orleans
Gulf of Mexico OCS Regional Office September 1999


Attachment 3

PLATFORM SYMBOL

TERMINAL SYMBOL

TAYLOR INDUSTRIES
MC 20

CPL S.P. 49 E-3
ONSHORE BOOSTERS

BRITISH PETROLEUM
MC 109

SP 45

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‘Chevron
nag Chevron Pipe Line Co. 10” South Pass 49
Mag Gull Coast Corridor Pipeline System

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DR RH CX DEW TXGNEER: DEF a0, 61-YD-13374

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11 Ba-54


Panel Investigation and Findings

is ready to receive deliveries. A PL OP [pipeline operations] order may be
issued, if appropriate, to affected FTL advising time and start-up and flow
rates.

c) “The CSCC and field personnel will keep accurate records during the
start-up and advise the appropriate FTL of any unusual events that may have
occurred during the start-up.

d) “Ifthe system is being restarted after being shut down for reasons other
than normal, volume in vs. volume out checks will be made after the first 15
minutes of operation and at 30 minute intervals until it is evident that the
line is operating normally.

e) “Ifthe flow rate deviates from the established rate during start-up, the
CSC will shut the system down following established shut down procedures

and notify the appropriate FTL.”

Thus, while CPL stated that they do not have established guidance on which
platform should begin pumping first following a major system upset, they do
provide for a system of checks and cross-checks to ensure that leaks can be

identified quickly.

As operator of MC 109, BP indicates that following severe weather

“ under no circumstances should deliveries commence without the
consent of the pipeline company.” Further, they indicated that their

“._. guidelines are not to start up if we have not established voice
communication.” BP correctly followed internal procedures, establishing
voice contact and obtaining consent from CPL to pump into the SP 49
system. It is unclear, however, if CPL gave instructions to BP on the need
for continued voice communications during startup regarding production

rates.

29


Panel Investigation and Findings

location as well as the number of producers pumping into the system at the

same time.

Simulations did show, however, that installing a back-pressure valve at SP
49 onshore with a valve setting of 410 psi, coupled with setting PSLs at 15
percent below the lowest operating pressure, would protect the pipeline
system in the event of a failure at the onshore facility water line (the worst-
case rupture scenario) even when all facilities were producing
simultaneously. All facilities would not shut down immediately on low
pressure, but would follow a domino effect as the operating pressure of the
pipeline was continually reduced as each facility dropped from the system.
Alternatively, it was found that an SP 49 Onshore back pressure of 525 psi,
coupled with setting PSLs at 15 percent below the lowest operating
pressure, produced a simultaneous shutdown of all facilities under the

worst-case rupture scenario.

As a result of the analysis, CPL has developed a recommended two-phase
approach for improving operational safety and the ability to identify pipeline
leaks quickly on the SP 49 pipeline system. The approach calls for the
simultaneous use of PSLs and SCADA as the primary method for leak
detection. The recommendation suggests that producers reset PSLs to 15
percent below their normal operating pressure and that SCADA be
configured to provide line balance information that can be trended.

38


Minerals Management Service
Gulf of Mexico OCS Region

U.S. Department of the Interior

IB4Iel@ee)

Managing America’s offshore energy
resources

Protecting America’s coastal
and marine environments


Panel Investigation and Findings

System Measurement Balance
The average daily production measured through MC 109 for the 8-month
period prior to September 1998 was 9,901 BPD. According to CPL reports,
the MC 109 LACT unit accounted for nearly all of the oil pumped after
coming back on line after the hurricane; MC 109 pumped for over 25 hours
after coming back on line before being shut in by the CSC because of the
suspicion of a leak. At an average startup rate of 333 barrels per hour, it was
possible to have pumped up to a maximum of 8,400 barrels of oil during the
subject operational period.

The latest pipeline balance receipts for the SP 49 system indicate that the
deliveries at the terminal were short approximately 9,677 barrels of oil for
September 1998. Review of the system receipts before and after the pipeline
spill January 1998 thru December 1998) shows that the pipeline system had
shortages as great as 5,683 barrels (1.1 % of receipts) and overages up to
6,742 barrels (1.5 % of receipts). For 1998, the SP 49 system showed a
shortage of 11,115 barrels (0.21 % of receipts). These imbalances may be
caused by such factors as:

1. Meter factors on the LACT units entering the system

2. Meter prover tolerances

3. Meter readings not taken precisely at seven each morning on the first of

each month.

24


Introduction

Incident Description — Post-Hurricane Startup Operations
By early afternoon on September 29, operators of the various facilities had
already or were in the process of transporting personnel back to their
platforms and were actively assessing platform damage and performing post-
hurricane inspections per individual operations manuals. Coordination of
startup operations of the SP 49 pipeline system was to be overseen by the
CPL Gulf Coast Operations Team, headed by the Region Operations
Manager. The team consisted of Field Team Leaders (FTL), the CSC Team
Leader, Tech Services and Health, Environment, and Safety staff personnel.

It should be noted that both SP 49 and MC 20 remained shut in following
the hurricane. The emphasis of this report is thus placed on operations of
CSC, SP 49 Onshore, MC 109, and SP 45, and events surrounding the
pipeline leak that occurred in SP Block 38.

Following the hurricane, Chevron staff inspected the onshore facilities for
damage. As there was no apparent significant damage, a standup test was
conducted on the West Bay System from SP 49 Onshore to the Empire
Terminal (see Attachment 2). The test was conducted on September 29,
from 1330 to 1430 hours, at a pressure of 238 psi. Discussions internal to
Chevron personnel resulted in the determination that a standup test was not
required for the offshore portion of the SP 49 system, as SCADA.
communications had been restored at that time. As SCADA was not,
however, operational for SP 49 Onshore, a Chevron employee was
dispatched to the tank battery to monitor tank levels and to relay this
information to the CSC controller for comparison to SCADA readings from
the facilities that would be pumping into the SP 49 pipeline system.


K. Gaudet

1/14/99
Page 5
Table 3
Location Knoop Microhardness
(500g)
Base Metal 190-200
HAZ 215-227
Weld Metal 205-215

Microhardness traverses across the weld were taken on several samples. Results are contained in the Table 3. A
slight increase in hardness along the HAZ was apparent but not significant.

Discussion

The failure of the pipeline weld was due to a combination of high pipeline stresses generated by the mudslide and
the fracture toughness of the material. Fracture toughness is the ability of a material to tolerate flaws or stress
concentrations without failing. As fracture toughness decreases, the stress at which a flaw of given size becomes
unstable is reduced. Once this “critical” stress level is reached, the flaw propagates in an uncontrolled manner
resulting in rapid fracture. Likewise, for a given level of stress, the lower the fracture toughness, the smaller the
flaw size at which it becomes unstable and propagates catastrophically. In either case, the stress level at failure is
often much less than the yield stress of the material and therefore the amount of plastic deformation at the fracture
surfaces is minimal.

Charpy impact values are often used as an indicator for the fracture toughness of a material. Based on the low
values reported in Table 2, poor base metal fracture toughness would have been expected. In addition, weld HAZ
typically exhibit values less than that of the base metal. Under normal operational stresses, the fracture toughness
was sufficient so that the existing stress concentrations and/or flaws along the weld were stable. However, when the
mudslide occurred, stresses on the pipe increased above normal levels to a point where the flaws were rendered
unstable and rapid fracture occurred. The fact that the cracked propagated primarily along the weld heat affected
zone is consistent with the fracture toughness being a minimum at this location and provided a path of least
resistance for crack propagation. Likewise, as characteristic of these “brittle” fractures, significant plastic
deformation at the fracture surfaces was not present.

The two cracks observed along the toe of the weld were formed as a result of corrosion-fatigue. They had existed
for some time as evidenced by the amount of corrosion products present in the cracks. Their orientation, with
respect to each other, 180° apart and on opposite sides of the weld, and propagation normal to the pipe surface
suggests the possibility of a cyclic bending stress in the line at this location. Nevertheless, the stresses generated
from the mudslide were in a direction such that propagation of these cracks did not occur.

C.N. Dykstal

K. Gaudet-1

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C.N. Dykstal-1

File-|

C.N. Dykstal File: 04.15.05, 18.10, 70.33


The installation of a back pressure valve set at 410 psi or 525 psi will shutdown the
10” pipeline if all four producers are pumping simultaneously and a pipeline rupture
occurred on the riser at the SP 49 Onshore Facility. However, creating 410 psi or
525 psi of back pressure on the system will most likely have serious economic
impacts on the producers for changing or resizing pumps and motors or engines.
Also, this will increase the emissions generated and the power consumption for each
producer thereby increasing each producers’ operating expense.

3.0 Operating Scenario - Ratable System

The following table summarizes the theoretical operating pressure if a single producer
were pumping ratably into the onshore storage tanks on the 10” SP 49 Onshore. This
would give the lowest operating pressure for each producer. Chevron Pipe Line Company
defines ratable pumping for a producer as a pump rate not greater than 120% of the
producer’s daily production. While this is the “ideal” operating scenario, it is not always
economical or feasible for the producers to modify their pumps.

In this operating scenario, ratable pumping for SP 45, MC 20 and SP 49 “A” is 20 BPH,
50 BPH and 250 BPH respectively. MC 109 pumping rate is the same used in Section 2.
The operating pressure for each producer will be significantly higher than the results
below when two, three or all four producers are pumping. Also, this operating scenario
will require the producers to reset their current PSL settings to 15% below the lowest
operating pressure; therefore, at the pipeline rupture locations studied, a theoretical PSL
setting is compared against a theoretical operating pressure.

Producer Lowest Theoretical
Operating Pressure
(psi)
SP 45 -17
MC 109 173
MC 20 7
SP 49 “A” 7
Table 3.0. Theoretical operating pressure for a single producer pumping ratably into
tankage at SP 49 Onshore.

SP 45 and MC 20 would not be able to pump as a single producer, since the
operating pressure for each platform is below the minimum PSL setting of 5 psi.
SP 45 would require both MC 109 and SP 49 “A” to be pumping to achieve an
operating pressure above the 5 psi PSL setting. MC 20 would require either MC
109 or SP 49 ”A” to be pumping to achieve and an operating pressure above the 5
psi PSL setting.

Page 15


Attachment 4
UNITED STATES GOVERNMENT

MEMORANDUM
February 1, 1999
To: Regional Director, Gulf of Mexico OCS Region (MS 5000)
From: Regional Supervisor, Field Operations, Gulf of Mexico OCS Region (MS 5200)
Regional Supervisor, Leasing and Environment, Gulf of Mexico OCS Region
(MS 5400)
Subject: October ‘98 Chevron Pipeline Oil Spill Environmental Impact and Response
Evaluation
Summary

. An oil slick developed from a leak in Chevron Pipeline’s 10” pipeline at South Pass 50, on
September 29, 1998.

. Favorable weather and currents kept the initial oil spill (3700 - 7500 bbls) offshore resulting
in no shoreline or wildlife impacts. The second release (85 bbls) was largely recovered or
naturally dispersed prior to impacting the shoreline.

. The spill response was appropriate, fast, efficient, effective.

. Shoreline impact from the October 4, 1998 oil spill (85 bbls) was minimal, with light sheens
along the eastern gulf side of Southwest Pass, from the Burrwood Cut southward to the rock
jetties. No wildlife impacts were observed.

. NRDA will likely not be pursued.

Background

After the passing of Hurricane Georges on September 28, 1998, BP Exploration started producing
into their 8" pipeline at 1900 hours on September 29, 1998. BP Exploration’s 8" pipeline

(seg # 9347) ties into Chevron Pipeline’s 10” pipeline (seg # 5625) through a subsea tie-in at

South Pass Block 50. At approximately 2000 hours on September 30, 1998, Chevron Pipeline called
BP Exploration and informed them that they were receiving no oil at the pipeline terminal. They
had pumped an estimated 7500 bbls of oil into the 8" pipeline; the observed slick size volume
estimate is 3700 bbls according to all the information reviewed. BP Exploration started their initial
response on October 1, 1998. Chevron Pipeline assumed responsibility for the response on
October 6, 1998, after it was discovered the leak was in their segment of the pipeline system:

Because of the inability to identify the leak location and confirm system integrity, a plan was
developed to pressure test the BP Exploration 8" pipeline from Mississippi Canyon 109 to Chevron
Pipeline’s 10” pipeline in South Pass 50. During the pressure test of the pipeline on October 4, they
noticed an oil sheen from the initial release, near South Pass Block 24/37. Response equipment on-
site for the test immediately began skimming operations. Fresh oil bubbles were observed at
approximately 1500 hours; this second release was estimated at 85 bbls. This release was from
Chevron Pipeline’s 10” pipeline.


3

area in the event of any wildlife impact. However, no impacted animals of any kind were observed
during this spill incident.

Natural Resource Damage Assessment (NRDA)

‘Throughout the oil spill response effort contractors specializing in NRDA assessments, hired by
both BP Exploration and Chevron Pipeline, conducted sampling and shoreline impact surveys in
anticipation of NRDA proceedings. The consensus among these contractors was: the shoreline
impact was not heavy enough to warrant a cleanup effort. Analysis of the samples taken has not
been conducted, based on the low likelihood that NRDA would be pursued.

NRDA trustees from state agencies (Louisiana Governor’s Office - Oil Spill Coordinator,
Department of Environmental Quality, Department of Natural Resources, Department of Wildlife
and Fisheries) and federal agencies (MMS, United States Coast Guard, Department of the Interior,
NOAA) were also actively involved during the oil spill response effort. According to Chevron
Pipeline, the trustees indicated that NRDA would probably not be pursued based on the minimal
impact on the shore and no observed wildlife impacts. The Louisiana Department of
Environmental Quality (DEQ) has indicated they may still conduct a follow up visual observation
of the impacted shoreline. If DEQ determines this trip is necessary, MMS representatives plan to
attend.

Orig. Sand Wiliam H. Martin (Orig. Sgd.) J. Hammond Eve
Donald C. Howard Hammond Eve
Attachments

cc: Howard w/attachs (MS 5200)
Eve w/attachs (MS 5400)
Wright w/attachs (MS 5231)
Pilie w/attachs (MS 5442)
MS 5000 Reading File

(Hw: right:kmd:02/01/99:g:\wordperf\rwright\chev-eva.wpd


Introduction

aware, through the use of restored SCADA, that MC 109 was pumping oil.
In fact, the SCADA communications with MC 109 had been restored since
0740 hours.

The CSC controller noted at 1000 hours that SCADA communications with
SP 49 Onshore had been restored, providing full access to data for

volumetric comparisons to assess system integrity.

At 2015 hours on September 30, following review of tank level readings
taken by the gauger, confirmation of tank gauge operation, and review of
SCADA data, MC 109 was ordered to shut down operations. The decision
followed CSC’s realization that MC 109 had been pumping oil into the

SP 49 pipeline system for approximately 25 hours without any apparent
change in levels in the SP 49 Onshore tank battery.

During its initial construction, the MC 109 pipeline was equipped with a
safety breakaway joint. The joint, which incorporates check valves, is
designed to fail when the pipeline is subjected to sufficient tension and
ensures that the amount of oil released due to the failure is minimized.
Given the assumption that this breakaway joint on the MC 109 pipeline had
parted, SP 45, which is downstream of MC 109, was allowed to remain on
production during the morning of October 1. It too, however, was
eventually ordered shut-in at 0715 hours, with production ceasing
approximately 15 minutes later. At this point, all potential sources that

could produce or pump oil into the SP 49 system were shut in.

The BP Incident Management System had been initiated during the previous
evening (September 30 at 2100 hours) through contact of the BP
Operations Section Chief following the orders from CPL to shut in

11